**UNITED
        STATES**
 **SECURITIES
        AND EXCHANGE COMMISSION**
 **Washington,
        D.C. 20549**
 
 
 **FORM
        10-Q**
 
 (Mark
                  One)**x**
              QUARTERLY
                  REPORT PURSUANT TO SECTION 13 OR 15(d)OF
                  THE SECURITIES EXCHANGE ACT OF 1934**For
                  the quarterly period ended March 31, 2007**
 
 ** ̈**
              TRANSITION
                  REPORT PURSUANT TO SECTION 13 OR 15(d)OF
                  THE SECURITIES EXCHANGE ACT OF 1934For
                  the transition period from  toCommission
                  File Number 001-10924
 
 **CLAYTON
        WILLIAMS ENERGY, INC.**
 (Exact
        name of registrant as specified in its charter)
 **Delaware**
              
              **75-2396863**(State
                  or other jurisdiction of incorporation or organization)
              
              (I.R.S.
                  Employer Identification No.)**Six
                  Desta Drive - Suite 6500****Midland,
                  Texas**
              
              **79705-5510**(Address
                  of principal executive offices)
              
              (Zip
                  code)Registrant’s
                  telephone number, including area code:
              
              **(432)
                  682-6324**
 
 **Not
        applicable**
 (Former
        name, former address and former fiscal year, if changed since last
        report)
 
 Indicate
                  by check mark whether the registrant (1) has filed all reports
                  required to
                  be filed by Section 13 or 15(d) of the Securities Exchange Act
                  of 1934
                  during the preceding 12 months (or for such shorter period that
                  the
                  Registrant was required to file such reports), and (2) has been
                  subject to
                  such filing requirements for the past 90 daysxYes
              
               ̈No
 
 Indicate
                  by check mark whether the registrant is a large accelerated filer,
                  an
                  accelerated filer, or a non-accelerated filer. See definition of
                  “accelerated filer and large accelerated filer” in Rule 12b-2 of the
                  Exchange Act.Large
                  accelerated filer ̈
              
              Accelerated
                  filerx
              
              Non-accelerated
                  filer ̈
 
 Indicate
                  by check mark whether the registrant is a shell company (as defined
                  in
                  Rule 12b-2 of the Exchange Act). ̈Yes
              
              xNo
 
 There
                  were 11,352,051 shares of Common Stock, $.10 par value, of the
                  registrant
                  outstanding as of May 7, 2007.
 
 
 
 
 
 ****
  
  **CLAYTON
        WILLIAMS ENERGY, INC**
 **TABLE
        OF CONTENTS**
 
 
 **PART
                  I. FINANCIAL INFORMATION****Page**Item
                  1.
              Financial
                  StatementsConsolidated
                  Balance Sheets as of March 31, 2007 and
                  December 31, 2006
              3Consolidated
                  Statements of Operations for
                  the three months ended March 31, 2007 and 2006
              5Consolidated
                  Statements of Stockholders’ Equity
                  for the three months ended March 31, 2007
              6Consolidated
                  Statements of Cash Flows for the three
                  months ended March 31, 2007 and 2006
              7Notes
                  to Consolidated Financial
                  Statements
              8Item
                  2.
              Management’s
                  Discussion and Analysis of Financial Conditions
                  and Results of Operations
              21Item
                  3.
              Quantitative
                  and Qualitative Disclosure About Market
                  Risks
              32Item
                  4.
              Controls
                  and Procedures
              34**PART
                  II. OTHER INFORMATION**Item
                  1.
              Legal
                  Proceedings
              35Item
                  1A.
              Risk
                  Factors
              35Item
                  6.
              Exhibits
              35Signatures
              37
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 ****
 
 
 2
  **CLAYTONWILLIAMS
        ENERGY, INC.**
 **CONSOLIDATED
        BALANCE SHEETS**
 **(Dollars
        in thousands)**
 
 **ASSETS****March
                  31,**
              
              **December
                  31,****2007**
              
              **2006****(Unaudited)**CURRENT
                  ASSETSCash
                  and cash equivalents
              
              $
              10,671
              
              $
              13,840Accounts
                  receivable:Oil
                  and gas sales
              
              
              26,327
              
              
              23,398Joint
                  interest and other, net
              
              
              17,103
              
              
              17,810Affiliates
              
              
              500
              
              
              2,436Inventory
              
              
              27,053
              
              
              40,392Deferred
                  income taxes
              
              
              505
              
              
              505Fair
                  value of derivatives
              
              
              13,088
              
              
              23,729Prepaids
                  and other
              
              
              3,857
              
              
              3,88899,104
              
              
              125,998PROPERTY
                  AND EQUIPMENTOil
                  and gas properties, successful efforts method
              
              
              1,275,920
              
              
              1,226,761Natural
                  gas gathering and processing systems
              
              
              18,099
              
              
              18,068Contract
                  drilling equipment
              
              
              82,487
              
              
              66,418Other
              
              
              16,032
              
              
              15,8481,392,538
              
              
              1,327,095Less
                  accumulated depreciation, depletion and amortization
              
              
              (698,263
              )
              
              (682,286
              )Property
                  and equipment, net
              
              
              694,275
              
              
              644,809OTHER
                  ASSETSDebt
                  issue costs, net
              
              
              7,791
              
              
              8,104Fair
                  value of derivatives
              
              
              120
              
              
              1,785Other
              
              
              17,780
              
              
              14,73725,691
              
              
              24,626$
              819,070
              
              $
              795,433
 
 
  The
            accompanying notes are an integral part of these consolidated financial
            statements.
 3
  **CLAYTON
        WILLIAMS ENERGY, INC.**
 **CONSOLIDATED
        BALANCE SHEETS**
 **(Dollars
        in thousands)**
 
 **LIABILITIES
                    AND STOCKHOLDERS' EQUITY****March
                    31,**
                
                **December
                    31,****2007**
                
                **2006****(Unaudited)**CURRENT
                    LIABILITIESAccounts
                    payable:Trade
                
                $
                73,218
                
                $
                75,815Oil
                    and gas sales
                
                
                13,231
                
                
                14,222Affiliates
                
                
                2,924
                
                
                1,407Current
                    maturities of long-term debt
                
                
                19,688
                
                
                17,397Fair
                    value of derivatives
                
                
                38,806
                
                
                29,722Accrued
                    liabilities and other
                
                
                6,850
                
                
                10,503154,717
                
                
                149,066NON-CURRENT
                    LIABILITIESLong-term
                    debt
                
                
                445,312
                
                
                413,876Deferred
                    income taxes
                
                
                28,744
                
                
                36,409Fair
                    value of derivatives
                
                
                18,713
                
                
                21,281Other
                
                
                32,842
                
                
                29,821525,611
                
                
                501,387COMMITMENTS
                    AND CONTINGENCIESSTOCKHOLDERS’
                    EQUITYPreferred
                    stock, par value $.10 per share, authorized - 3,000,000shares;
                    none
                    issued
                
                
                -
                
                
                -Common
                    stock, par value $.10 per share, authorized - 30,000,000 shares;
                    issuedand
                    outstanding - 11,352,051 shares in 2007 and 11,152,051 shares
                    in
                    2006
                
                
                1,135
                
                
                1,115Additional
                    paid-in capital
                
                
                120,017
                
                
                113,965Retained
                    earnings
                
                
                17,590
                
                
                29,900138,742
                
                
                144,980$
                819,070
                
                $
                795,433
 
  The
            accompanying notes are an integral part of these consolidated financial
            statements.
 4
  **CLAYTON
        WILLIAMS ENERGY,
        INC.**
 **CONSOLIDATED
        STATEMENTS OF OPERATIONS**
 **(Unaudited)**
 **(In
        thousands, except per share)**
 
 **Three
                  Months Ended****March
                  31,****2007**
              
              **2006**REVENUESOil
                  and gas sales
              
              $
              61,180
              
              $
              60,181Natural
                  gas services
              
              
              2,654
              
              
              3,196Drilling
                  rig services
              
              
              8,417
              
              
              -Gain
                  on sales of property and equipment
              
              
              128
              
              
              17Total
                  revenues
              
              
              72,379
              
              
              63,394COSTS
                  AND EXPENSESProduction
              
              
              17,278
              
              
              14,965Exploration:Abandonments
                  and impairments
              
              
              11,105
              
              
              12,843Seismic
                  and other
              
              
              890
              
              
              3,101Natural
                  gas services
              
              
              2,413
              
              
              2,829Drilling
                  rig services
              
              
              4,933
              
              
              -Depreciation,
                  depletion and amortization
              
              
              15,231
              
              
              14,710Impairment
                  of property and equipment
              
              
              565
              
              
              -Accretion
                  of abandonment obligations
              
              
              618
              
              
              379General
                  and administrative
              
              
              3,903
              
              
              4,067Loss
                  on sales of property and equipment
              
              
              -
              
              
              13Total
                  costs and expenses
              
              
              56,936
              
              
              52,907Operating
                  income
              
              
              15,443
              
              
              10,487OTHER
                  INCOME (EXPENSE)Interest
                  expense
              
              
              (7,629
              )
              
              (4,339
              )Loss
                  on derivatives
              
              
              (16,849
              )
              
              (1,572
              )Other
              
              
              (8,488
              )
              
              618Total
                  other income (expense)
              
              
              (32,966
              )
              
              (5,293
              )Income
                  (loss) before income taxes and minority interest
              
              
              (17,523
              )
              
              5,194Income
                  tax (expense) benefit
              
              
              6,080
              
              
              (1,818
              )Minority
                  interest, net of tax
              
              
              (867
              )
              
              -NET
                  INCOME (LOSS)
              
              $
              (12,310
              )
              $
              3,376Net
                  income (loss) per common share:Basic
              
              $
              (1.09
              )
              $
              0.31Diluted
              
              $
              (1.09
              )
              $
              0.30Weighted
                  average common shares outstanding:Basic
              
              
              11,290
              
              
              10,841Diluted
              
              
              11,290
              
              
              11,351
 
 
  The
            accompanying notes are an integral part of these consolidated financial
            statements.
 5
  **CLAYTON
        WILLIAMS ENERGY, INC.**
 **CONSOLIDATED
        STATEMENTS OF STOCKHOLDERS' EQUITY**
 **(Unaudited)**
 **(In
        thousands)**
 
 
 **Common
                    Stock****No.
                    of**
                
                **Par**
                
                **Paid-In**
                
                **Retained****Shares**
                
                **Value**
                
                **Capital**
                
                **Earnings**BALANCE,December
                    31, 2006
                
                
                11,152
                
                $
                1,115
                
                $
                113,965
                
                $
                29,900Net
                    loss and total comprehensive loss
                
                
                -
                
                
                -
                
                
                -
                
                
                (12,310
                )Issuance
                    of stock through compensation plans
                
                
                200
                
                
                20
                
                
                6,052
                
                
                -BALANCE,March
                    31, 2007
                
                
                11,352
                
                $
                1,135
                
                $
                120,017
                
                $
                17,590
 
   The
            accompanying notes are an integral part of these consolidated financial
            statements.
 6
  **CLAYTON
        WILLIAMS ENERGY, INC.**
 **CONSOLIDATED
        STATEMENTS OF CASH FLOWS**
 **(Unaudited)**
 **(In
        thousands)**
 
 **Three
                  Months Ended****March
                  31,****2007**
              
              **2006**CASH
                  FLOWS FROM OPERATING ACTIVITIESNet
                  income (loss)
              
              $
              (12,310
              )
              $
              3,376Adjustments
                  to reconcile net income (loss) to cashprovided
                  by operating activities:Depreciation,
                  depletion and amortization
              
              
              15,231
              
              
              14,710Impairment
                  of property and equipment
              
              
              565
              
              
              -Exploration
                  costs
              
              
              11,105
              
              
              12,843Gain
                  on sales of property and equipment, net
              
              
              (128
              )
              
              (4
              )Deferred
                  income taxes
              
              
              (6,080
              )
              
              1,818Non-cash
                  employee compensation
              
              
              610
              
              
              605Unrealized
                  (gain) loss on derivatives
              
              
              18,822
              
              
              (6,505
              )Settlements
                  on derivatives with financing elements
              
              
              5,593
              
              
              7,921Amortization
                  of debt issue costs
              
              
              309
              
              
              371Accretion
                  of abandonment obligations
              
              
              618
              
              
              379Minority
                  interest, net of tax
              
              
              867
              
              
              -Changes
                  in operating working capital:Accounts
                  receivable
              
              
              (286
              )
              
              4,046Accounts
                  payable
              
              
              (3,703
              )
              
              867Other
              
              
              5,016
              
              
              (2,891
              )Net
                  cash provided by operating activities
              
              
              36,229
              
              
              37,536CASH
                  FLOWS FROM INVESTING ACTIVITIESAdditions
                  to property and equipment
              
              
              (55,749
              )
              
              (75,616
              )Additions
                  to equipment of Larclay JV.
              
              
              (19,316
              )
              
              -Proceeds
                  from sales of property and equipment
              
              
              645
              
              
              29Change
                  in equipment inventory
              
              
              3,896
              
              
              (937
              )Other
              
              
              (2,970
              )
              
              (6,534
              )Net
                  cash used in investing activities
              
              
              (73,494
              )
              
              (83,058
              )CASH
                  FLOWS FROM FINANCING ACTIVITIESProceeds
                  from long-term debt
              
              
              25,000
              
              
              56,000Proceeds
                  from long-term debt of Larclay JV
              
              
              8,727
              
              
              -Repayments
                  of long-term debt
              
              
              -
              
              
              (7
              )Proceeds
                  from sale of common stock
              
              
              5,962
              
              
              175Settlements
                  on derivatives with financing elements
              
              
              (5,593
              )
              
              (7,921
              )Net
                  cash provided by financing activities
              
              
              34,096
              
              
              48,247NET
                  INCREASE (DECREASE) IN CASH ANDCASH
                  EQUIVALENTS
              
              
              (3,169
              )
              
              2,725CASH
                  AND CASH EQUIVALENTSBeginning
                  of period
              
              
              13,840
              
              
              5,935End
                  of period
              
              $
              10,671
              
              $
              8,660SUPPLEMENTAL
                  DISCLOSURESCash
                  paid for interest, net of amounts capitalized
              
              $
              11,739
              
              $
              8,212
   The
              accompanying notes are an integral part of these consolidated financial
              statements.
 7
  **CLAYTON
        WILLIAMS ENERGY, INC.**
 **NOTES
        TO CONSOLIDATED FINANCIAL STATEMENTS**
 **March
        31, 2007**
 **(Unaudited)**
 
 **1.** **Nature
        of Operations**
 
 Clayton
        Williams Energy, Inc. (a Delaware corporation) and its subsidiaries
        (collectively, the “Company” or “CWEI”) is an independent oil and gas company
        engaged in the exploration for and development and production of oil and
        natural
        gas primarily in its core areas in Texas,
        Louisiana and New Mexico. Approximately 20% of the Company’s outstanding common
        stock is beneficially owned by Clayton W. Williams, Jr. (“Mr. Williams”),
        Chairman of the Board and Chief Executive Officer of the Company, and
        approximately 27% is owned by a partnership in which Mr. Williams’ adult
        children are limited partners.
 
 Substantially
        all of the Company’s oil and gas production is sold under short-term contracts
        which are market-sensitive. Accordingly, the Company’s financial condition,
        results of operations, and capital resources are highly dependent upon
        prevailing market prices of, and demand for, oil and natural gas. These
        commodity prices are subject to wide fluctuations and market uncertainties
        due
        to a variety of factors that are beyond the control of the Company. These
        factors include the level of global demand for petroleum products, foreign
        supply of oil and gas, the establishment of and compliance with production
        quotas by oil-exporting countries, weather conditions, the price and
        availability of alternative fuels, and overall economic conditions, both
        foreign
        and domestic.
 
 **2.** **Presentation**
 
 The
        preparation of these consolidated financial statements in conformity with
        accounting principles generally accepted in the United States requires
        management of the Company to make estimates and assumptions that affect the
        reported amounts of assets and liabilities and disclosure of contingent assets
        and liabilities at the date of the financial statements and the reported
        amounts
        of revenues and expenses during the reporting periods. Actual results could
        differ materially from those estimates.
 
 The
        consolidated financial statements include the accounts of Clayton Williams
        Energy, Inc., its wholly-owned subsidiaries and the accounts of the Larclay
        JV
        (see Note 11). The Company also accounts for its undivided interests in oil
        and
        gas limited partnerships using the proportionate consolidation method, whereby
        its share of assets, liabilities, revenues and expenses are consolidated
        with
        other operations. All significant intercompany transactions and balances
        associated with the consolidated operations have been eliminated.
 
 In
        the
        opinion of management, the Company's unaudited consolidated financial statements
        as of March 31, 2007 and for the interim periods ended March 31, 2007 and
        2006
        include all adjustments which are necessary for a fair presentation in
        accordance with accounting principles generally accepted in the United States.
        These interim results are not necessarily indicative of the results to be
        expected for the year ending December 31, 2007.
 
 Certain
        information and footnote disclosures normally included in financial statements
        prepared in accordance with accounting principles generally accepted in the
        United States have been condensed or omitted in this Form 10-Q pursuant to
        the
        rules and regulations of the Securities and Exchange Commission (“SEC”). These
        consolidated financial statements should be read in conjunction with the
        audited
        consolidated financial statements and notes thereto included in the Company's
        Form 10-K for the year ended December 31, 2006.
 
 **3.** **Recent
        Accounting Pronouncements**
  In
          September 2006, the Securities and Exchange Commission issued Staff Accounting
          Bulletin No. 108 (“SAB 108”), which became effective on January 1,
          2007. SAB 108 provides guidance on the consideration of the effects of
          prior
          period misstatements in quantifying current year misstatements for the
          purpose
          of a materiality assessment. SAB 108 requires an entity to evaluate the
          impact
          of correcting all misstatements, including both the carryover and reversing
          effects of prior year misstatements, on current year financial statements.
          If a
          misstatement is material to the current year financial statements, the
          prior
          year financial statements should also be corrected, even
 8
 though
          such revision was, and continues to be, immaterial to the prior year financial
          statements. Correcting prior year financial statements for immaterial errors
          would not require previously filed reports to be amended. Such correction
          should
          be made in the current period filings. The adoption of SAB 108 had no
          effect on the Company’s consolidated financial statements.
  In
        September 2006, the Financial Accounting Standards Board (“FASB”) issued
        Statement of Financial Accounting Standards (“SFAS”) No. 157 *Fair
        Value Measurements* (“SFAS 157”), which defines fair value, establishes a framework for
        measuring fair value in generally accepted accounting principles and expands
        disclosures about fair value measurements. This Statement applies under other
        accounting pronouncements that require or permit fair value measurements,
        the
        FASB having previously concluded in those accounting pronouncements that
        fair
        value is the relevant measurement attribute. Accordingly, this Statement
        does
        not require any new fair value measurements. SFAS 157 is effective for fiscal
        years beginning after December 15, 2007. The Company plans to adopt SFAS
        157 beginning in the first quarter of 2008. The Company is currently evaluating
        the impact, if any, the adoption of SFAS 157 will have on its consolidated
        financial position, results of operations or cash flows.
 
 In
        February 2007, the FASB issued SFAS No. 159 *The
        Fair Value Option for Financial Assets and Financial Liabilities - Including
        an
        Amendment of FASB Statement No. 115* (“SFAS 159”).
        SFAS 159 permits an entity to choose to measure many financial instruments
        and certain other items at fair value. The fair value option established
        by
        SFAS 159 permits all entities to choose to measure eligible items at fair
        value at specified election dates. Unrealized gains and losses on items for
        which the fair value option has been elected are to be recognized in earnings
        at
        each subsequent reporting date. SFAS 159 is effective for financial statements
        issued for fiscal years beginning after November 15, 2007. The effect of
        adopting SFAS 159 has not been determined, but it is not expected to have
        a
        significant effect on the Company’s consolidated financial position or results
        of operations.
 
 In
        June
        2006, the FASB issued Interpretation No. 48 *Accounting
        for Uncertainty in Income Taxes* (“FIN 48”) to clarify the manner in which enterprises account for
        uncertainties in their provisions for income taxes. Generally, the standard
        presented by FIN 48 is a “more likely than not” standard and is intended to
        enhance the relevancy and comparability of financial reporting by companies.
        FIN 48 is effective for fiscal years beginning after December 31,
        2006. The Company adopted FIN 48 effective January 1, 2007 (see Note
        10).
 
 **4.** **Long-Term
        Debt**
 
 Long-term debt consists of the following:
 
 **March
                  31,**
              
              **December
                  31,****2007**
              
              **2006****(In
                  thousands)**73⁄4%
                  Senior Notes due 2013
              
              $
              225,000
              
              $
              225,000Secured
                  bank credit facility, due May 2009
              
              
              165,000
              
              
              140,000Secured
                  term loan of Larclay JV
              
              
              75,000
              
              
              66,273465,000
              
              
              431,273Less
                  current maturities(a)
              
              
              (19,688
              )
              
              (17,397
              )$
              445,312
              
              $
              413,876
 (a) Consists
        of current portion of term loan of Larclay JV.
 
 *73⁄4% Senior Notes due 2013*
 In
        July
        2005, the Company issued, in a private placement, $225 million of aggregate
        principal amount of 73⁄4% Senior Notes due 2013 (“Senior Notes”). The Senior Notes
        were issued at face value and bear interest at 73⁄4% per year, payable
        semi-annually on February 1 and August 1 of each year, beginning February
        1,
        2006. After the payment of typical transaction expenses, net proceeds of
        approximately $217 million were used to repay all amounts outstanding
  9
 under
          the
          secured bank credit facilities and for general corporate purposes, including
          the
          funding of planned exploration and development activities.
  At any time prior to August 1, 2008, the Company may redeem up to 35% of
          the
          aggregate principal amount of the Senior Notes with the proceeds of certain
          equity offerings at a redemption price of 107.75% of the principal amount,
          plus
          accrued and unpaid interest. In addition, prior to August 1, 2009, the
          Company
          may redeem some or all of the Senior Notes at a redemption price equal
          to 100%
          of the principal amount of the Senior Notes to be redeemed, plus a make-whole
          premium, plus any accrued and unpaid interest. On and after August 1, 2009,
          the
          Company may redeem some or all of the Senior Notes at redemption prices
          (expressed as percentages of principal amount) equal to 103.875% for the
          twelve-month period beginning on August 1, 2009, 101.938% for the
          twelve-month period beginning on August 1, 2010, and 100.00% beginning
          on August
          1, 2011, for any period thereafter, in each case plus accrued and unpaid
          interest.
 
 The
        Indenture governing the Senior Notes restricts the ability of the Company
        and
        its restricted subsidiaries to: (i) borrow money; (ii) issue
        redeemable and preferred stock; (iii) pay distributions or dividends;
        (iv) make investments; (v) create liens without securing the Senior
        Notes; (vi) enter into agreements that restrict dividends from
        subsidiaries; (vii) sell certain assets or merge with or into other
        companies; (viii) enter into transactions with affiliates;
        (ix) guarantee indebtedness; and (x) enter into new lines of business.
        The Company was in compliance with these covenants at March 31,
        2007.
 
 *Secured
        Bank Credit Facility*
 The
        Company’s secured bank credit facility provides for a revolving loan facility in
        an amount not to exceed the lesser of the borrowing base, as established
        by the
        banks, or that portion of the borrowing base determined by the Company to
        be the
        elected borrowing limit.  The borrowing base, which is based on the
        discounted present value of future net revenues from oil and gas production,
        is
        subject to redetermination at any time, but at least semi-annually in May
        and
        November, and is made at the discretion of the banks.  If, at any time, the
        redetermined borrowing base is less than the amount of outstanding indebtedness,
        the Company will be required to (i) pledge additional collateral, (ii) prepay
        the excess in not more than five equal monthly installments, or (iii) elect
        to
        convert the entire amount of outstanding indebtedness to a term obligation
        based
        on amortization formulas set forth in the loan agreement.  Substantially
        all of the Company’s oil and gas properties are pledged to secure advances under
        the credit facility. At March 31, 2007, the borrowing base established by
        the
        banks was $200 million, with no monthly commitment reductions.  After
        allowing for outstanding letters of credit totaling $5.8 million, the
        Company had $29.2 million available under the credit facility at March 31,
        2007.
 
 The
        revolving credit facility provides for interest at rates based on the agent
        bank’s prime rate plus margins ranging from .25% to 1%, or if elected by the
        Company based on LIBOR plus margins ranging from 1.5% to 2.25%. The Company
        also
        pays a commitment fee on the unused portion of the revolving credit facility.
        Interest and fees are payable at least quarterly. The effective annual interest
        rate on borrowings under the combined credit facility, excluding bank fees
        and
        amortization of debt issue costs, for the three months ended March 31, 2007
        was 7.6%.
 
 The
        loan
        agreement applicable to the revolving credit facility contains financial
        covenants that are computed quarterly. The working capital covenant requires
        the
        Company to maintain a ratio of current assets to current liabilities of at
        least
        1 to 1. Another financial covenant under the credit facility requires the
        Company to maintain a ratio of indebtedness to cash flow of no more than
        3
        to 1. The computations of current assets, current liabilities, cash flow
        and indebtedness are defined in the loan agreement. The Company was in
        compliance with all financial and non-financial covenants at March 31,
        2007.
 
 *Secured
        Term Loan of Larclay JV*
 In
        connection with the Company’s investment in Larclay JV
        (see
        Note 11), Larclay JV obtained a $75 million secured term loan facility from
        a lender to finance the construction and equipping of 12 new drilling rigs.
        The
        Larclay JV term loan is secured by substantially all of the assets of Larclay
        JV. Initially, the Company pledged additional collateral in the form of a
        $19 million letter of credit. In February 2007, the letter of credit was
        cancelled and replaced by a $19.5 million guaranty from the Company. In
        March 2007, the Company issued a $5 million letter of credit which expires
        in
        June 2007 as additional collateral under the term loan to cover any temporary
        shortfall in collateral value caused by delays in completing construction
        of the
        final drilling rigs being financed by the lender. Concurrently, the guaranty
        was
        amended to limit the Company’s combined credit exposure under the guaranty and
        the letter of the credit
  10
 to
          $19.5
          million. Although the Company is not a maker on the Larclay JV term loan,
          it is providing additional credit support for the Larclay JV term loan and
          is required to fully consolidate the accounts of Larclay JV under FASB
          Interpretation No. 46R Consolidation of Variable Interest Entities - or
          Interpretation of ARB No. 51 (as amended) (“FIN 46R”).
  The
        Larclay JV term loan, as amended, bears interest at a floating rate based
        on a
        LIBOR average, plus 3.25%, and provides for monthly interest payments through
        June 2007 and monthly principal and interest payments thereafter sufficient
        to
        retire the principal balance by 35% in the first year, 25% in each of the
        next
        two years, and 15% in the fourth year. Two voluntary prepayments of $10 million
        each may be made in 2008 and 2009 without a prepayment penalty. The Larclay
        JV
        term loan prohibits Larclay JV from making any cash distributions to the
        Company
        or Lariat until the balance on the term loan is fully repaid, and repayments
        by
        Larclay JV of any loans by the Company or Lariat are subordinated to the
        loans
        outstanding under the term loan and are subject to other restrictions. At
        March
        31, 2007, the effective interest rate on the Larclay JV term loan was
        8.7%.
 
 **5.** **Other
        Non-Current Liabilities**
 
 Other
        non-current liabilities consist of the following:
 
 **March
                  31,**
              
              **December
                  31,****2007**
              
              **2006****(In
                  thousands)**Abandonment
                  obligations
              
              $
              28,428
              
              $
              27,846Minority
                  interest, net of tax
              
              
              1,941
              
              
              1,074Other
                  taxes payable
              
              
              1,585
              
              
              -Other
              
              
              888
              
              
              901$
              32,842
              
              $
              29,821
 
 
 Changes
        in abandonment obligations for the three months ended March 31, 2007 and
        2006 are as follows:
 
 **Three
                  Months Ended****March
                  31,****2007**
              
              **2006****(In
                  thousands)**Beginning
                  of period
              
              $
              27,846
              
              $
              19,447Additional
                  abandonment obligations from new wells
              
              
              145
              
              
              328Sales
                  or abandonments of properties
              
              
              (181
              )
              
              (82
              )Revisions
                  of previous estimates
              
              
              -
              
              
              (17
              )Accretion
                  expense
              
              
              618
              
              
              379End
                  of period
              
              $
              28,428
              
              $
              20,055
 
 
 **6.** **Compensation
        Plans**
 
 *Stock-Based Compensation*
 The
        Company has reserved 1,798,200 shares of common stock for issuance under
        the
        1993 Stock Compensation Plan (“1993 Plan”). The Plan provides for the issuance
        of nonqualified stock options with an exercise price which is not less than
        the
        market value of the Company’s common stock on the date of grant. All options
        granted through March 31, 2007 expire 10 years from the date of grant and
        become
        exercisable based on varying vesting schedules. The Company issues new shares,
        not repurchased shares, to option holders that exercise stock options under
        the
        plans.
  The
        Company has reserved 86,300 shares of common stock for issuance under the
        Outside Directors Stock Option Plan (“Directors Plan”). Since the inception of
        the Directors Plan, the Company has issued options covering
  11
 48,000
          shares of common stock at option prices ranging from $3.25 to $41.74 per
          share.
          All outstanding options expire 10 years from the grant date and are fully
          exercisable upon issuance.
 
 The
        following table sets forth certain information regarding the Company’s stock
        option plans as of and for the three months ended March 31,
        2007:
 
 **Weighted****Weighted**
              
              **Average****Average**
              
              **Remaining**
              
              **Aggregate****Exercise**
              
              **Contractual**
              
              **Intrinsic****Shares**
              
              **Price**
              
              **Term**
              
              **Value
                  (a)**Outstanding
                  at January 1, 2007
              
              
              1,009,485
              
              $
              22.27Granted
              
              
              4,000
              
              $
              36.31Exercised
                  (b)
              
              
              (200,000
              )
              $
              29.85Outstanding
                  at March 31, 2007
              
              
              813,485
              
              $
              20.47
              
              
              5.8
              
              $
              6,423,092Vested
                  at March 31, 2007
              
              
              813,485
              
              $
              20.47
              
              
              5.8
              
              $
              6,423,092Exercisable
                  at March 31, 2007
              
              
              813,485
              
              $
              20.47
              
              
              5.8
              
              $
              6,423,092
 (a) Based
        on closing price at March 31, 2007 of $28.37 per share.
 (b) Cash
        received for options exercised totaled $6 million.
 
 
 The
        following table summarizes information with respect to options outstanding
        at
        March 31, 2007, all of which are currently exercisable.
 
 **Outstanding
                  and Exercisable Options****Weighted****Weighted**
              
              **Average****Average**
              
              **Remaining****Exercise**
              
              **Life
                  in****Shares**
              
              **Price**
              
              **Years**Range
                  of exercise prices:$5.50
              
              
              33,485
              
              $
              5.50
              
              
              2.1$10.00
                  - $19.74
              
              
              462,000
              
              $
              17.49
              
              
              5.1$22.90
                  - $41.74
              
              
              318,000
              
              $
              26.38
              
              
              7.3813,485
              
              $
              20.47
              
              
              5.8
 
 The
        following table presents certain information regarding stock-based compensation
        amounts for the three months ended March 31, 2007 and 2006.
 
 **Three
                  Months Ended****March
                  31,****2007**
              
              **2006****(In
                  thousands, except per share)**Weighted
                  average grant date fair value of options granted per share
              
              $
              27.56
              
              $
              31.91Intrinsic
                  value of options exercised
              
              $
              228
              
              $
              1,374Stock-based
                  employee compensation expense
              
              $
              110
              
              $
              128Tax
                  benefit
              
              $
              (39
              )
              $
              (45
              )Net
                  stock-based employee compensation expense
              
              $
              71
              
              $
              83
  *After-Payout Incentive Plan*
 The
        Compensation Committee of the Board of Directors has adopted an incentive
        plan
        for officers, key employees and consultants, excluding Mr. Williams, who
        promote the Company’s drilling and acquisition programs. Management’s objective
        in adopting this plan is to further align the interests of the participants
        with
        those of the
  12
 Company
          by granting the participants an after-payout interest in the production
          developed, directly or indirectly, by the participants. The plan generally
          provides for the creation of a series of partnerships or participation
          arrangements (“APO Arrangements”) between the Company and the participants to
          which the Company contributes a portion of its economic interest in wells
          drilled or acquired within certain areas. Generally, the Company pays all
          costs
          and receives all revenues until payout of its costs, plus interest. At
          payout,
          the participants receive 99% to 100% of all subsequent revenues and pay
          99% to
          100% of all subsequent expenses attributable to the APO
          Arrangements.
 
 Between
        3% and 7.5% of the Company’s economic interests in specified wells drilled or
        acquired by the Company subsequent to October 2002 are subject to APO
        Arrangements (excluding properties acquired in a merger with Southwest
        Royalties, Inc. in May 2004). The Company records its allocable share of
        the
        assets, liabilities, revenues, expenses and oil and gas reserves of these
        APO
        Arrangements in its consolidated financial statements. The Company recognized
        $500,000 of non-cash compensation expense during each of the three-month
        periods
        ended March 31, 2007 and 2006 for the estimated fair value of the APO
        Arrangements granted during those periods.
 
 *SWR
        Reward Plan*
 In
        January 2007, the Company granted awards under the Southwest Royalties Reward
        Plan (the “SWR Reward Plan”), a one-time incentive plan designed to reward
        eligible employees and other service providers for continued quality service
        to
        the Company, and to encourage retention of those employees and service providers
        by providing them the opportunity to receive bonus payments that are based
        on
        certain profits derived from a portion of the Company’s working interest in the
        RS Windham C3 well in Upton County, Texas. Eligible participants in the SWR
        Reward Plan include those officers, key employees and consultants, excluding
        Mr. Williams, who made significant contributions to the acquisition and
        development of Southwest Royalties, Inc.
 
 The
        SWR
        Reward Plan provides for quarterly cash bonuses to the participants, as a
        group,
        equal to the after-payout cash flow from a 22.5% working interest in the
        RS
        Windham C3 well. Two-thirds of the quarterly bonus amount is payable to the
        participants until the full vesting date of October 25, 2011. After the full
        vesting date, the deferred portion of the quarterly bonus amount, with interest
        at 4.83% per year, as well as 100% of all subsequent quarterly bonus amounts,
        are payable to participants. The quarterly bonus amounts are allocated among
        the
        participants based on each participant’s bonus percentage.
 
 To
        continue as a participant in the SWR Reward Plan, participants must remain
        in
        the employment or service of the Company through the full vesting date.
        Participants who remain in the employment or service of the Company through
        the
        full vesting date will continue as participants for the duration of the SWR
        Reward plan, subject to certain restrictions. The full vesting date may occur
        sooner than October 25, 2011 in the event of a change of control or sale
        transaction, as defined in the SWR Reward Plan.
 
 The
        Company recognizes compensation expense related to the SWR Reward Plan over
        the
        vesting period. For the quarter ended March 31, 2007, the Company recorded
        compensation expense of $97,000 for the SWR Reward Plan.
 
 **7.** **Derivatives**
 
 *Commodity Derivatives*
 From
        time
        to time, the Company utilizes commodity derivatives, consisting of swaps,
        floors
        and collars, to attempt to optimize the price received for its oil and gas
        production. When using swaps to hedge oil and natural gas production, the
        Company receives a fixed price for the respective commodity and pays a floating
        market price as defined in each contract (generally NYMEX futures prices),
        resulting in a net amount due to or from the counterparty. In floor
        transactions, the Company receives a fixed price (put strike price) if the
        market price falls below the put strike price for the respective commodity.
        If
        the market price is greater than the put strike price, no payments are due
        from
        either party. Costless collars are a combination of puts and calls, and contain
        a fixed floor price (put strike price) and ceiling price (call strike price).
        If
        the market price for the respective commodity exceeds the call strike price
        or
        falls below the put strike price, then the Company receives the fixed price
        and
        pays the market price. If the market price is between the call and the put
        strike prices, no payments are due from either party. Commodity derivatives
        are
        settled monthly as the contract production periods mature.
 
 13
 The
        following summarizes information concerning the Company’s net positions in open
        commodity derivatives applicable to periods subsequent to March 31, 2007.
        The settlement prices of commodity derivatives are based on NYMEX futures
        prices.
 
 **Collars:**
 **Gas**
              
              **Oil****MMBtu****(a)**
              
              **Floor**
              
              **Ceiling**
              
              **Bbls**
              
              **Floor**
              
              **Ceiling**Production
                  Period:2ndQuarter 2007
              
              
              459,000
              
              $
              4.00
              
              $
              5.18
              
              
              141,000
              
              $
              23.00
              
              $
              25.203rdQuarter 2007
              
              
              459,000
              
              $
              4.00
              
              $
              5.18
              
              
              141,000
              
              $
              23.00
              
              $
              25.204thQuarter 2007
              
              
              459,000
              
              $
              4.00
              
              $
              5.18
              
              
              141,000
              
              $
              23.00
              
              $
              25.202008
              
              
              1,279,000
              
              $
              4.00
              
              $
              5.15
              
              
              392,000
              
              $
              23.00
              
              $
              25.072,656,000
              
              
              
              
              
              
              
              
              815,000
 
 **Swaps:**
 **Gas**
                
                **Oil****MMBtu****(a)**
                
                **Price**
                
                **Bbls**
                
                **Price**Production
                    Period:2ndQuarter 2007
                
                
                2,600,000
                
                $
                8.16
                
                
                -
                
                $
                -3rdQuarter 2007
                
                
                2,400,000
                
                $
                8.34
                
                
                75,000
                
                $
                72.754thQuarter 2007
                
                
                2,400,000
                
                $
                8.34
                
                
                225,000
                
                $
                72.752008
                
                
                6,300,000
                
                $
                8.19
                
                
                720,000
                
                $
                65.6013,700,000
                
                
                
                
                
                1,020,000
 (a) One
        MMBtu equals one Mcf at a Btu factor of 1,000.
 In January 2007, the Company terminated certain fixed-price oil swaps covering
        375,000 barrels at a price of $55.35 per barrel from April 2007 through August
        2007, resulting in an aggregate realized gain of approximately
        $6.5 million, which will be collected from the counterparty monthly during
        2007.
 
 In
        July
        2006, the Company also terminated certain fixed-price oil swaps covering
        225,000
        barrels at a price of $80.45 per barrel from April 2007 through December
        2007,
        resulting in an aggregate loss of approximately $1.8 million, which will be
        paid to the counterparty monthly during 2007.
 
 *Interest Rate Derivatives*
 The
        Company is a party to interest rate swaps that were acquired in connection
        with
        the acquisition of Southwest Royalties, Inc. in May 2004. Under these
        derivatives, the Company pays a fixed rate for the notional principal balances
        and receives a floating market rate based on LIBOR. The interest rate swaps
        are
        settled quarterly. The following summarizes information concerning the Company’s
        net positions in open interest rate swaps applicable to periods subsequent
        to
        March 31, 2007.
 
 **Interest
        Rate Swaps:**
 **Principal**
              
              **Fixed**
                **Libor****Balance**
              
              **Rates**Period:April
                  1, 2007 to November 1, 2007
              
              $
              50,000,000
              
              
              5.19
              %November
                  1, 2007 to November 1, 2008
              
              $
              45,000,000
              
              
              5.73
              %
  *Accounting For Derivatives*
 The
        Company accounts for its derivatives in accordance with Statement of Financial
        Accounting Standards No. 133 *Accounting
        for Derivative Instruments and Hedging Activities* (“SFAS 133”), as amended. The Company did not designate any of its
        currently open commodity or interest rate derivatives as cash flow hedges;
        therefore, all
  14
 changes
          in the fair value of these contracts prior to maturity, plus any realized
          gains
          or losses at maturity, are recorded as other income (expense) in the Company’s
          statements of operations. For the three months ended March 31, 2007, the
          Company reported a $16.8 million loss on derivatives, consisting of an
          $18.8 million loss related to changes in mark-to-market valuations and a
          $2 million realized gain on settled contracts. For the three months ended
          March 31, 2006, loss on derivatives was $1.6 million, consisting of a
          $6.5 million gain related to changes in mark-to-market valuations and an
          $8.1 million realized loss on settled contracts.
 
 **8.** **Financial
        Instruments**
 
 Cash
        and
        cash equivalents, receivables, accounts payable and accrued liabilities were
        each estimated to have a fair value approximating the carrying amount due
        to the
        short maturity of those instruments. Indebtedness under the secured bank
        credit
        facility was estimated to have a fair value approximating the carrying amount
        since the interest rate is generally market sensitive. The estimated fair
        value
        of the Company’s Senior Notes at March 31, 2007 and December 31, 2006
        was approximately $209.8 million and $207.6 million,
        respectively.
 
 The
        fair
        values of derivatives as of March 31, 2007 and December 31, 2006 are set
        forth below. The associated carrying values at these dates are equal to their
        estimated fair values.
 
 **March 31,**
              
              **December
                  31,****2007**
              
              **2006****(In
                  thousands)**Assets
                  (liabilities):Commodity
                  derivatives
              
              $
              (43,944
              )
              $
              (25,289
              )Interest
                  rate derivatives
              
              
              (367
              )
              
              (200
              )Net
                  liabilities
              
              $
              (44,311
              )
              $
              (25,489
              )
 
 **9.** **Inventory**
 
 The
        Company maintains an inventory of tubular goods and other well equipment
        for use
        in its exploration and development drilling activities. Any gains or losses
        on
        disposition of inventory, and any losses on write-down of inventory to its
        estimated market value, are reported as other income /expense in the accompanying consolidated statements of operations. For the three
        months
        ended March 31, 2007, the Company reported losses on inventory of
        $9. 2 million. No
        losses were recorded in the 2006 period. The 2007 period included a non-cash charge of $8.9  million
        to write-down inventory to its estimated market value at March 31, 2007.
        The
        write-down resulted primarily from the sale of certain surplus equipment
        at an
        auction in March 2007. The Company received $4.5  million
        of net proceeds from
        the
        auction in
        April 2007 when the auction sale was consummated.
 
 **10.** **Income
        Taxes**
 
 The
        Company’s effective federal and state income tax rate for the three months ended
        March 31, 2007 of 34.7% differed from the statutory federal rate of 35% due
        to
        tax benefits derived from statutory depletion deductions, offset in part
        by
        increases in the tax provision related primarily to the effects of the
        recently-enacted Texas Margin Tax and certain non-deductible
        expenses.
 
 The
        Company and its subsidiaries file federal income tax returns with the United
        States Internal Revenue Service (“IRS”) and state income tax returns in various
        state tax jurisdictions. As a general rule, the Company’s tax returns for fiscal
        years after 2002 currently remain subject to examination by appropriate taxing
        authorities. None of the Company’s income tax returns are under examination at
        this time.
 
 The
        Company adopted FASB Interpretation No. 48, *Accounting for Uncertainty in
        Income Taxes (“FIN 48”)*, effective January 1, 2007. Upon adoption of FIN
        48, the Company recorded a $1.6 million liability for taxes payable related
        to unrecognized tax benefits arising from uncertain tax positions taken by
        the
        Company in previous periods. No additional unrecognized tax benefits originated
        during the quarter ended March 31, 2007. The tax liability recorded
  15
 under
          FIN
          48 is included in other non-current liabilities in the accompanying consolidated
          balance sheet at March 31, 2007.
  All
        of
        the unrecognized tax benefits at March 31, 2007 relate to tax positions for
        which the ultimate deductibility is highly certain but for which there is
        uncertainty about the timing of such deductions. Because of the impact of
        deferred tax accounting, the disallowance of the shorter deduction period
        would
        not affect the annual effective tax rate but would only change the amount
        of
        deferred tax assets related to net operating loss carryforwards.
 
 The
        Company recognizes interest and penalties accrued related to unrecognized
        tax
        benefits in interest expense. Due to the Company’s net operating loss positions,
        no interest or penalties have been accrued on the Company’s unrecognized tax
        benefits.
 
 The
        Company currently plans to make all required filings with the appropriate
        tax
        jurisdictions in 2007 to reduce or eliminate the uncertainties that resulted
        in
        the establishment of this tax liability under FIN 48.
 
 **11.** **Investments**
 
 *West
        Coast Energy Properties, L.P.*
 In
        August
        2006, an affiliated partnership, West Coast Energy Properties, L.P. (“WCEP”),
        acquired certain producing oil and gas assets in California and Texas for
        aggregate cash consideration of approximately $58 million. Approximately
        75% of the purchase price relates to properties in three fields in southern
        California, and the remaining 25% relates primarily to properties located
        in
        Mitchell County, Texas.
 
 WCEP
        is a
        Texas limited partnership formed to facilitate this acquisition, the general
        partner of which is a limited liability company owned by the Company and
        the
        limited partner of which is an affiliate of GE Energy Financial Services.
        Under
        the partnership agreement, the general partner contributed approximately
        $6.2 million to the partnership for an initial partnership interest of 5%,
        which interest can increase to 37.63%, and ultimately to 49%, upon the
        achievement of certain target rates of return.
 
 The
        Company financed its equity contribution to the general partner through
        borrowings on its revolving credit facility.
 
 *Larclay
        JV*
 In
        April
        2006, the Company formed a joint venture (“Larclay JV”) with Lariat Services,
        Inc. (“Lariat”) to construct, own and operate 12 new drilling rigs. The Company
        and Lariat each own a 50% interest in Larclay JV. The rigs are being constructed
        on behalf of Larclay JV by Lariat, as operations manager. Ten of the rigs
        were
        fully constructed at March 31, 2007. The remaining two rigs are expected
        to be
        fully constructed by June 2007. The total construction cost of all rigs,
        excluding capitalized interest, is expected to be approximately
        $79 million. A lender has provided a $75 million secured term loan to
        Larclay JV to finance most of the cost of constructing and initially equipping
        the rigs. The Company is not a maker on the Larclay JV term loan, but it is
        providing additional credit support for the Larclay JV term loan (see
        Note 4).
 
 Also
        in
        April 2006, the Company entered into a three-year drilling contract with
        Larclay
        JV assuring the availability of each rig for use in the ordinary course of
        the
        Company’s exploration and development drilling program throughout the term of
        the drilling contract. The provisions of the drilling contract provide that
        the
        Company contract for each rig on a well-by-well basis at then current market
        rates. If a rig is not needed by the Company at any time during the term
        of the
        contract, Larclay JV may contract with other operators for the use of such
        rig,
        subject to certain restrictions. If a rig is idle, the Company will pay Larclay
        JV an idle rig rate ranging from $8,100 per day to $10,300 per day (plus
        crew
        labor expenses, if applicable), depending on the size of the rig. The Company’s
        maximum potential obligation to pay idle rig rates over the term of this
        drilling contract, excluding any crew labor expenses, totals approximately
        $103 million at March 31, 2007.
 
 Although
        the Company and Lariat own equal interests in Larclay JV, the Company meets
        the
        definition of the primary beneficiary of Larclay JV’s expected cash flows under
        FIN 46R. As the primary beneficiary under FIN 46R, the Company is required
        to
        include the accounts of Larclay JV in the Company’s consolidated financial
  16
 statements.
          As of March 31, 2007, Lariat’s equity ownership in the net assets of Larclay JV
          was $1.9 million, which is recorded as minority interest and included in
          other non-current liabilities in the accompanying consolidated financial
          statements. The Company’s intercompany accounts with Larclay JV have been
          eliminated in consolidation.
  **12.** **Commitments
        and Contingencies**
 
 *Purchase
        Commitments*
 The
        Company is presently obligated under firm orders for two drilling rigs and
        related equipment in an aggregate amount of $24.5 million, for which cash
        deposits totaling $11.5 million have been paid to the equipment suppliers
        as of March 31, 2007. The total cost of the rigs, when completed and fully
        equipped, is estimated to be approximately $27 million. The rigs are
        scheduled for delivery in mid-2007.
 
 In
        addition to the Larclay JV drilling contract discussed in Note 11, the
        Company has also entered into three drilling contracts with third party drilling
        contractors and is obligated to make payments under these contracts totaling
        $9 million in 2007.
 
 *Legal
        Proceedings*
 The Company is a co-plaintiff in a lawsuit involving a dispute over rights
        to
        produce hydrocarbons under certain leases in Alabama. The parties to the
        lawsuit
        have tentatively agreed to settle the lawsuit. Once the agreement is executed
        and binding, the Company will record a gain on settlement of approximately
        $2.9 million. Final settlement is expected to occur in the second quarter
        of 2007.
  The Company is a defendant in several lawsuits that have arisen in the ordinary
        course of business. While the outcome of these lawsuits cannot be predicted
        with
        certainty, management does not expect any of these to have a material adverse
        effect on the Company’s consolidated financial condition or results of
        operations.
  **13.** **Oil
        and Gas Properties**
 
 The
        following sets forth the capitalized costs for oil and gas properties as
        of
        March 31, 2007 and December 31, 2006.
 **March
                    31,**
                  **2007**
                
                **December
                    31, 2006****(In
                    thousands)**Proved
                    properties
                
                $
                1,137,063
                
                $
                1,097,341Unproved
                    properties
                
                
                138,857
                
                
                129,420Total
                    capitalized costs
                
                
                1,275,920
                
                
                1,226,761Accumulated
                    depreciation, depletion and amortization
                
                
                (668,387
                )
                
                (654,316
                )Net
                    capitalized costs
                
                $
                607,533
                
                $
                572,445
 
 
 In
        April
        2005, the Financial Accounting Standards Board issued Staff Position
        No. 19-1 (“FSP 19-1”). FSP 19-1 amends the present guidance in
        Statement of Financial Accounting Standards No. 19, paragraphs 31 and 34,
        regarding when exploratory drilling costs pending determination of proved
        reserves can be carried as an asset of an oil and gas company that uses the
        successful efforts method of accounting. The Company was required to adopt
        FSP 19-1, including its disclosures, effective July 1, 2005. The adoption
        of FSP 19-1 did not have a significant impact on the Company’s results of
        operations. At March 31, 2007 and December 31, 2006, the Company had
        capitalized $34.1 million and $27 million, respectively, of
        exploratory drilling costs applicable to wells that were pending determination
        of proved reserves. Of the $27 million costs at December 31, 2006,
        $16.2 million was subsequently deemed productive and the remaining
        $10.8 million was still pending determination of proved
        reserves.
 
 17
 **14.**  **Segment
        Information**
 
 In
        accordance with Statement of Financial Accounting Standards No. 131 *Disclosures
        about Segments of an Enterprise and Related Information* (“SFAS 131”), the Company has two reportable operating segments, which are
        oil and gas exploration and production and contract drilling services. Beginning
        in April 2006, the Company formed the Larclay JV, a contract drilling joint
        venture that the Company consolidates in its financial statements (see
        Note 11). Effective January 1, 2007, the contract drilling segment meets
        the quantitative thresholds under SFAS 131 to be considered a reportable
        operating segment and, accordingly, is shown as “Contract Drilling” in the table
        below.
 
 The
        following table presents selected financial information regarding the Company’s
        operating segments for the three-month periods ended March 31, 2007 and
        2006.
 
 **For
                  the Three Months Ended**
                **March
                  31, 2007**
              
              **Oil
                  and Gas**
              
              **Contract
                  Drilling**
              
              **Intercompany**
                **Eliminations**
              
              **ConsolidatedTotal****(In
                  thousands)**Revenues
              
              $
              63,962
              
              $
              10,936
              
              $
              (2,519
              )
              $
              72,379Depreciation,
                  depletion and amortization (a)
              
              
              14,413
              
              
              1,607
              
              
              (224
              )
              
              15,796Other
                  operating expenses (b)
              
              
              36,175
              
              
              5,827
              
              
              (862
              )
              
              41,140Interest
                  expense
              
              
              6,795
              
              
              834
              
              
              -
              
              
              7,629Other
                  (income) expense
              
              
              25,337
              
              
              -
              
              
              -
              
              
              25,337Income
                  before income taxesandminority
                  interest
              
              
              (18,758
              )
              
              2,668
              
              
              (1,433
              )
              
              (17,523
              )Income
                  tax(expense)
                  benefit
              
              
              7,014
              
              
              (934
              )
              
              -
              
              
              6,080Minority
                  interest, net of tax
              
              
              -
              
              
              (867
              )
              
              -
              
              
              (867
              )Net
                  income(loss)
              
              $
              (11,744
              )
              $
              867
              
              $
              (1,433
              )
              $
              (12,310
              )Total
                  assets
              
              $
              730,651
              
              $
              92,350
              
              $
              (3,931
              )
              $
              819,070Additions
                  to property and equipment
              
              $
              72,776
              
              $
              5,765
              
              $
              (1,433
              )
              $
              77,108
 
 
 **For
                  the Three Months Ended**
              
              
              
              
              
              **Intercompany**
              
              **Consolidated****March
                  31, 2006**
              
              **Oil
                  and Gas**
              
              **Other**
              
              **Eliminations**
              
              **Total****(In
                  thousands)**Revenues
              
              $
              63,394
              
              $
              -
              
              $
              -
              
              $
              63,394Depreciation,
                  depletion and amortization (a)
              
              
              14,710
              
              
              -
              
              
              -
              
              
              14,710Other
                  operating expenses (b)
              
              
              38,197
              
              
              -
              
              
              -
              
              
              38,197Interest
                  expense
              
              
              4,339
              
              
              -
              
              
              -
              
              
              4,339Other
                  (income) expense
              
              
              954
              
              
              -
              
              
              -
              
              
              954Income
                  before income taxes
              
              
              5,194
              
              
              -
              
              
              -
              
              
              5,194Income
                  tax expense
              
              
              (1,818
              )
              
              -
              
              
              -
              
              
              (1,818
              )Net
                  income
              
              $
              3,376
              
              $
              -
              
              $
              -
              
              $
              3,376Total
                  assets
              
              $
              632,662
              
              $
              -
              
              $
              -
              
              $
              632,662Additions
                  to property and equipment
              
              $
              68,302
              
              $
              -
              
              $
              -
              
              $
              68,302
 (a)
            Includes
                impairment of property and equipment. (b)
            Includes
                the following expenses: production, exploration, natural gas services,
                accretion of abandonment obligations, general and administrative
                and loss
                on sales of property and equipment. 
 18
 **15.** **Guarantor
        Financial Information**
 
 In
        July
        2005, Clayton Williams Energy, Inc. (“Issuer”) issued $225 million of
        Senior Notes (see Note 4). Other than West Coast Energy Properties GP, LLC
        (“WCEP LLC”), the general partner of WCEP (see Note 11), all of the
        Issuer’s wholly-owned and active subsidiaries (“Guarantor Subsidiaries”) have
        jointly and severally, irrevocably and unconditionally guaranteed the
        performance and payment when due of all obligations under the Senior Notes.
        Larclay JV, a 50%-owned drilling rig joint venture formed in April 2006,
        and
        WCEP, LLC have not guaranteed the Senior Notes and are referred to in this
        Note 15 as Non-Guarantor Entities.
 
 The
        financial information which follows sets forth the Company’s condensed
        consolidating financial statements as of and for the periods
        indicated.
  **Condensed
        Consolidating Balance Sheet**
 **March
        31, 2007**
 **(Dollars
                  in thousands)**
              
              
              
              
              
              **Non-****Guarantor**
              
              **Guarantor**
              
              **Adjustments/****Issuer**
              
              **Subsidiaries**
              
              **Entities**
              
              **Eliminations**
              
              **Consolidated**Current
                  assets
              
              $
              134,991
              
              $
              97,845
              
              $
              12,603
              
              $
              (146,335
              )
              $
              99,104Property
                  and equipment, net
              
              
              329,066
              
              
              279,449
              
              
              85,760
              
              
              -
              
              
              694,275Investments
                  in subsidiaries
              
              
              71,445
              
              
              -
              
              
              -
              
              
              (71,445
              )
              
              -Other
                  assets
              
              
              24,756
              
              
              326
              
              
              609
              
              
              -
              
              
              25,691Total
                  assets
              
              $
              560,258
              
              $
              377,620
              
              $
              98,972
              
              $
              (217,780
              )
              $
              819,070Current
                  liabilities
              
              $
              90,857
              
              $
              178,423
              
              $
              31,772
              
              $
              (146,335
              )
              $
              154,717Non-current
                  liabilities:Long-term
                  debt
              
              
              390,000
              
              
              -
              
              
              55,313
              
              
              -
              
              
              445,313Fair
                  value of derivatives
              
              
              3,423
              
              
              15,290
              
              
              -
              
              
              -
              
              
              18,713Other
              
              
              5,142
              
              
              56,337
              
              
              106
              
              
              -
              
              
              61,585398,565
              
              
              71,627
              
              
              55,419
              
              
              -
              
              
              525,611Stockholders’
                  equity
              
              
              70,836
              
              
              127,570
              
              
              11,781
              
              
              (71,445
              )
              
              138,742Total
                  liabilities andstockholders’
                  equity
              
              $
              560,258
              
              $
              377,620
              
              $
              98,972
              
              $
              (217,780
              )
              $
              819,070
 
 **Condensed
        Consolidating Balance Sheet**
 **December
        31, 2006**
 **(Dollars
                  in thousands)**
              
              
              
              
              
              **Non-****Guarantor**
              
              **Guarantor**
              
              **Adjustments/****Issuer**
              
              **Subsidiaries**
              
              **Entities**
              
              **Eliminations**
              
              **Consolidated**Current
                  assets
              
              $
              160,772
              
              $
              96,386
              
              $
              11,781
              
              $
              (142,941
              )
              $
              125,998Property
                  and equipment, net
              
              
              293,775
              
              
              279,913
              
              
              71,121
              
              
              -
              
              
              644,809Investments
                  in subsidiaries
              
              
              72,171
              
              
              -
              
              
              -
              
              
              (72,171
              )
              
              -Other
                  assets
              
              
              23,638
              
              
              358
              
              
              630
              
              
              -
              
              
              24,626Total
                  assets
              
              $
              550,356
              
              $
              376,657
              
              $
              83,532
              
              $
              (215,112
              )
              $
              795,433Current
                  liabilities
              
              $
              89,704
              
              $
              176,876
              
              $
              25,427
              
              $
              (142,941
              )
              $
              149,066Non-current
                  liabilities:Long-term
                  debt
              
              
              365,000
              
              
              -
              
              
              48,876
              
              
              -
              
              
              413,876Fair
                  value of derivatives
              
              
              313
              
              
              20,968
              
              
              -
              
              
              -
              
              
              21,281Other
              
              
              10,257
              
              
              55,870
              
              
              103
              
              
              -
              
              
              66,230375,570
              
              
              76,838
              
              
              48,979
              
              
              -
              
              
              501,387Stockholders’
                  equity
              
              
              85,082
              
              
              122,943
              
              
              9,126
              
              
              (72,171
              )
              
              144,980Total
                  liabilities andstockholders’
                  equity
              
              $
              550,356
              
              $
              376,657
              
              $
              83,532
              
              $
              (215,112
              )
              $
              795,433
  19
 **Condensed
        Consolidating Statement of Operations**
 **Three
        Months Ended March 31, 2007**
 **(Dollars
                  in thousands)**
              
              
              
              
              
              **Non-****Guarantor**
              
              **Guarantor**
              
              **Adjustments/****Issuer**
              
              **Subsidiaries**
              
              **Entities**
              
              **Eliminations**
              
              **Consolidated**Total
                  revenue
              
              $
              40,005
              
              $
              24,169
              
              $
              11,038
              
              $
              (2,833
              )
              $
              72,379Costs
                  and expenses
              
              
              35,570
              
              
              16,139
              
              
              7,575
              
              
              (2,348
              )
              
              56,936Operating
                  income (loss)
              
              
              4,435
              
              
              8,030
              
              
              3,463
              
              
              (485
              )
              
              15,443Other
                  income (expense)
              
              
              (28,758
              )
              
              (3,402
              )
              
              (806
              )
              
              -
              
              
              (32,966
              )Income
                  tax benefit
              
              
              6,080
              
              
              -
              
              
              -
              
              
              -
              
              
              6,080Minority
                  interest, net of tax
              
              
              (867
              )
              
              -
              
              
              -
              
              
              -
              
              
              (867
              )Net
                  income (loss)
              
              $
              (19,110
              )
              $
              4,628
              
              $
              2,657
              
              $
              (485
              )
              $
              (12,310
              )
 
 **Condensed
        Consolidating Statement of Operations**
 **Three
        Months Ended March 31, 2006**
 **(Dollars
                  in thousands)**
              
              
              
              
              
              **Non-****Guarantor**
              
              **Guarantor**
              
              **Adjustments/****Issuer**
              
              **Subsidiaries**
              
              **Entities**
              
              **Eliminations**
              
              **Consolidated**Total
                  revenue
              
              $
              37,014
              
              $
              27,033
              
              $
              -
              
              $
              (653
              )
              $
              63,394Costs
                  and expenses
              
              
              36,782
              
              
              16,778
              
              
              -
              
              
              (653
              )
              
              52,907Operating
                  income (loss)
              
              
              232
              
              
              10,255
              
              
              -
              
              
              -
              
              
              10,487Other
                  income (expense)
              
              
              (4,291
              )
              
              (1,002
              )
              
              -
              
              
              -
              
              
              (5,293
              )Income
                  tax expense
              
              
              (1,818
              )
              
              -
              
              
              -
              
              
              -
              
              
              (1,818
              )Net
                  income (loss)
              
              $
              (5,877
              )
              $
              9,253
              
              $
              -
              
              $
              -
              
              $
              3,376
 
 **Condensed
        Consolidating Statement of Cash Flows**
 **Three
        Months Ended March 31, 2007**
 **(Dollars
                  in thousands)**
              
              
              
              
              
              **Non-****Guarantor**
              
              **Guarantor**
              
              **Adjustments/****Issuer**
              
              **Subsidiaries**
              
              **Entities**
              
              **Eliminations**
              
              **Consolidated**Operating
                  activities
              
              $
              8,042
              
              $
              13,657
              
              $
              14,306
              
              $
              224
              
              $
              36,229Investing
                  activities
              
              
              19,114
              
              
              (5,460
              )
              
              (87,424
              )
              
              276
              
              
              (73,494
              )Financing
                  activities
              
              
              (32,185
              )
              
              (8,346
              )
              
              75,127
              
              
              (500
              )
              
              34,096Net
                  increase (decrease) incash
                  and cash equivalents
              
              
              (5,029
              )
              
              (149
              )
              
              2,009
              
              
              -
              
              
              (3,169
              )Cash
                  at the beginning ofthe
                  period
              
              
              12,542
              
              
              1,298
              
              
              -
              
              
              -
              
              
              13,840Cash
                  at end of the period
              
              $
              7,513
              
              $
              1,149
              
              $
              2,009
              
              $
              -
              
              $
              10,671
 
 **Condensed
        Consolidating Statement of Cash Flows**
 **Three
        Months Ended March 31, 2006**
 **(Dollars
                  in thousands)**
              
              
              
              
              
              **Non-****Guarantor**
              
              **Guarantor**
              
              **Adjustments/****Issuer**
              
              **Subsidiaries**
              
              **Entities**
              
              **Eliminations**
              
              **Consolidated**Operating
                  activities
              
              $
              10,784
              
              $
              26,752
              
              $
              -
              
              $
              -
              
              $
              37,536Investing
                  activities
              
              
              (68,694
              )
              
              (14,364
              )
              
              -
              
              
              -
              
              
              (83,058
              )Financing
                  activities
              
              
              59,622
              
              
              (11,375
              )
              
              -
              
              
              -
              
              
              48,247Net
                  increase (decrease) incash
                  and cash equivalents
              
              
              1,712
              
              
              1,013
              
              
              -
              
              
              -
              
              
              2,725Cash
                  at the beginning ofthe
                  period
              
              
              4,302
              
              
              1,633
              
              
              -
              
              
              -
              
              
              5,935Cash
                  at end of the period
              
              $
              6,014
              
              $
              2,646
              
              $
              -
              
              $
              -
              
              $
              8,660
  20
 **Item
        2 -**  **Management's
        Discussion and Analysis of Financial Condition and Results of
        Operations**
 
 The
        following discussion is intended to provide information relevant to an
        understanding of our financial condition, changes in our financial condition
        and
        our results of operations and cash flows and should be read in conjunction
        with
        our consolidated financial statements and notes thereto included elsewhere
        in
        this Form 10- Q
        and in
        our Form 10-K for the year ended December 31, 2006.
  **Overview**
 
 We are an oil and natural gas exploration, development, acquisition, and
        production company. Our basic business model is to find and develop oil and
        gas
        reserves through exploration and development activities, and sell the production
        from those reserves at a profit. To be successful, we must, over time, be
        able
        to find oil and gas reserves and then sell the resulting production at a
        price
        that is sufficient to cover our finding costs, operating expenses,
        administrative costs and interest expense, plus offer us a return on our
        capital
        investment. From time to time, we may also acquire producing properties if
        we
        believe the acquired assets offer us the potential for reserve growth through
        additional developmental or exploratory drilling activities.
 
 We believe that the economic climate in the domestic oil and gas industry
        continues to be suitable for our business model. Although oil prices have
        retreated from their peaks in mid-2006, and gas prices have been volatile,
        we
        believe that supply and demand fundamentals in the energy marketplace continue
        to provide us with the economic incentives necessary for us to assume the
        risks
        we face in our search for oil and gas reserves. However, we are experiencing
        a
        shrinking profit margin resulting from rising drilling and production costs.
        While profit margins still remain favorable, operating metrics per Mcfe,
        such as
        finding costs, production costs, and depreciation, depletion and amortization
        (“DD&A”) expense, are generally on an upward trend.
 
 Finding
        quality domestic oil and gas reserves through exploration is a significant
        challenge and involves a high degree of risk. Our planned exploration activities
        in 2007 offer us the opportunity to add significant oil and gas reserves
        through
        the drilling of several potentially high-impact wells, particularly in our
        East
        Texas Bossier area. However, these wells are very expensive to drill and
        involve
        a high degree of risk.
  **Key
        Factors to Consider**
 
 The following summarizes the key factors considered by management in the
        review
        of our financial condition and operating performance for the
        first
        quarter of 2007 and the outlook for the remainder of 2007.
 
 ·
            We
                spent $60.6 million on exploration and development activities during
                the first three months of 2007, of which approximately 75% was on
                exploratory prospects. We currently plan to spend approximately
                $186.2 million for fiscal 2007, of which approximately 78% is
                estimated to be spent on exploratory prospects. These expenditures
                for the
                first quarter of 2007 exceeded our cash flow from operating activities
                by
                approximately $24.3 million. Our expenditures for the remainder of
                2007 are also expected to exceed our cash flow from operating activities,
                although not by as large a margin. We cannot predict our drilling
                success
                on exploratory prospects, and our future results of operations and
                financial condition could be adversely affected by unsuccessful
                exploratory drilling results. 
 ·
            During
                the first quarter of 2007, we increased borrowings under our revolving
                credit facility by $25 million from $140 million at December 31,
                2006 to $165 million at March 31, 2007 to partially finance our
                exploration and development activities.  ·
            Despite
                our high level of capital spending in fiscal 2006 and the first quarter
                of
                2007, our oil and gas production for the three months ended March
                31, 2007
                was only 11% higher on an Mcfe basis than in the comparable period
                in
                2006, despite production curtailments in the 2006 period caused by
                hurricane damage. A significant portion of our fiscal 2006 and first
                quarter 2007 expenditures have not resulted in current production
                because
                they relate to (a) unproved exploratory prospects, (b) drilling or
                completion activities that are in progress, or (c) non-productive
                leasing
                and drilling activities. 
 21
 ·
            At
                March 31, 2007, our capitalized unproved oil and gas properties totaled
                $138.9 million, of which approximately $105 million was
                attributable to unproved acreage. Unproved properties are subject
                to a
                valuation impairment to the extent the carrying cost of a prospect
                exceeds
                its estimated fair value. Therefore, our results of operations in
                future
                periods may be adversely affected by unproved property
                impairments. 
 ·
            Exploration
                costs related to abandonments and impairments were $11.1 million in
                the first quarter of 2007, of which approximately $10 million related
                to unsuccessful well costs and $1.1 million related to impairment of
                unproved acreage. Most of the abandonment and impairment costs in
                the
                first quarter of 2007 related to prospects in South Louisiana and
                Utah. ·
              We
                  recorded a $16.8 million net loss on derivatives in the first quarter
                  of 2007. Net cash received from counterparties accounted for a
                  $2 million gain on settled contracts and changes in mark-to-market
                  valuations accounted for an $18.8 million loss. Since we do not
                  presently designate our derivatives as cash flow hedges under applicable
                  accounting standards, we recognize the full effect of changing
                  prices on
                  mark-to-market valuations as a current charge or credit to our
                  results of
                  operations. 
 ·
              We
                  recorded a $9.2 million loss on inventory during the quarter ended
                  March 31, 2007 due primarily to a write-down of certain surplus
                  equipment
                  to its estimated realizable value. Most of this write-down related
                  to
                  equipment that we sold through an auction process in March 2007.
                  Net
                  proceeds from the auction of $4.5 million were received in April
                  2007.
 **Recent
        Exploration and Developmental Activities**
 
 ***Overview***
 As shown in “Liquidity and Capital Resources - Capital Expenditures,” we
        incurred expenditures for exploration and development activities of
        $60.6 million during the first three months of 2007. Approximately 75% of
        our first quarter 2007 expenditures were related to exploratory drilling
        activities. We also increased our estimates for capital expenditures in fiscal
        2007 from $170.1 million to $186.2 million.
 
 In addition to our on-going drilling program in the Miocene Trends of South
        Louisiana and our Cotton Valley/Hosston exploration program in North Louisiana,
        we have begun an aggressive exploratory drilling program targeting the deep
        Bossier formation in North Louisiana and East Texas.
 
 ***South
        Louisiana***
 Prior to 2007, we had drilled 67 gross (53.6 net) exploratory wells in South
        Louisiana, of which 34 gross (25.9 net) were completed as producers. The
        following table sets forth certain information about our exploratory and
        developmental well activities in South Louisiana subsequent to December 31,
        2006.
 
 **Working**
              
              **Current****Spud
                  Date**
              
              **Well
                  Name (Prospect)**
              
              **Interest**
              
              **Status**April
                  2006
              
              Cobena
                  #1 (Boa II)
              
              63%
              
              CompletingJanuary
                  2007
              
              SL
                  195 QQ #7 (Floyd)
              
              100%
              
              Waiting
                  on pipelineFebruary
                  2007
              
              SL
                  195 QQ #10 (Floyd)
              
              75%
              
              Waiting
                  on pipelineFebruary
                  2007
              
              Orleans
                  Levee District #2 (American Bay)
              
              45%
              
              Waiting
                  on pipelineMarch
                  2007
              
              Bowie
                  Lumber Co. #1 (Bayou Boeuf)
              
              100%
              
              DryApril
                  2007
              
              Pivach
                  Agency #1 (Elsa)
              
              94%
              
              Dry
  We continue to attempt to complete the Cobena #1, a 15,250-foot exploratory
        well
        in Acadia Parish in the Boa II prospect on which drilling operations began
        in April 2006. We temporarily abandoned the Discorbis 3 sand due to mechanical
        difficulties, and are currently testing the Discorbis 2 sand to which the
        Company had attributed approximately 2.3 Bcfe of net gas reserves at December
        31, 2006. Based on these recent test results, we currently plan to abandon
        the
        Discorbis 2 sand and will eliminate all proved reserve estimates previously
        assigned to this sand. Together with our partners in the well, we are currently
        evaluating well completion data in the Discorbis 3 sand to
  22
 determine
          if the potential for proved reserves from this sand justifies a second
          completion attempt. If we decide to abandon the well, we will record exploration
          expense for cumulative well costs, plus any impaired acreage cost, at the
          time
          of determination. To date, we have incurred approximately $9.8 million in
          drilling and completion costs on this well, net to our interest, and have
          approximately $1 million of acreage attributable to this prospect that
          is
          subject to impairment.
 
 In
        our
        Floyd prospect, we have drilled ten wells to date, of which eight are currently
        producing. The remaining two wells have been completed and are waiting on
        pipeline construction. Currently, the eight wells are producing at combined
        rates of approximately 6,700 Mcf of gas per day and 450 barrels of oil per
        day,
        net to our interest. However, due to production facility constraints, this
        current level of combined production is significantly less than the combined
        rates at which these wells are capable of producing. In order to fully resolve
        these capacity issues, we plan to build our own plant and production facilities
        in 2007 to process and market gas production from all the wells in the
        prospect.
 
 We
        drilled and abandoned the Bowie Lumber Co. #1, a 13,150-foot exploratory
        well in
        the Bayou Boeuf prospect in Lafourche Parish, after it was determined to
        be
        non-productive. We recorded a $3.8 million pre-tax charge related to the
        abandonment of the well in the first quarter of 2007.
 
 We
        drilled and completed a second well in the American Bay prospect, the Orleans
        Levee District #2. This development well, which was completed in the Tex
“W”
sand at 13,986 feet, has been tested and is currently waiting on a pipeline
        connection. We own a 45% working interest in this well.
 
 We
        also
        drilled and abandoned a 3,500-foot exploratory well, the Pivach Agency #1
        (Elsa), when it was determined to be incapable of producing hydrocarbons
        in
        economic quantities. We recorded a pre-tax charge in the first quarter of
        2007
        of approximately $200,000, and expect to record an additional charge of
        approximately $1 million in the second quarter for the abandonment of this
        well.
 
 ***North
        Louisiana***
 In
        2005,
        we began an exploration program in North Louisiana targeting the Cotton
        Valley/Hosston and Bossier formations. In this area, the Cotton Valley/Hosston
        formations are encountered at depths ranging from 8,000 to 12,000 feet, and
        the Bossier formation is encountered at depths ranging from 11,000 to
        15,500 feet. We believe that these tight sandstone formations have become
        more economically viable due to higher product prices, coupled with enhanced
        drilling and completion techniques.
 
 Prior
        to
        2007, we had drilled 4 gross (3.7 net) exploratory wells in North
        Louisiana, of which 2 gross (1.7 net) were completed as producers. The
        following table sets forth certain information about our exploratory well
        activities in North Louisiana subsequent to December 31, 2006. This table
        does
        not include non-operated wells.
 
 **Working**
              
              **Current****Spud
                  Date**
              
              **Well
                  Name (Prospect)**
              
              **Interest**
              
              **Status**October
                  2006
              
              P.
                  Benoit #1 (Sarepta)
              
              91%
              
              Waiting
                  on completionJanuary
                  2007
              
              J.L.
                  Hood #1 (Terryville)
              
              86%
              
              ProducingFebruary
                  2007
              
              J.
                  Huey #1 (Terryville)
              
              86%
              
              ProducingMarch
                  2007
              
              David
                  Barton #1 (Winnsboro)
              
              100%
              
              DrillingMarch
                  2007
              
              George
                  Staton #1 (Sarepta)
              
              70%
              
              Waiting
                  on completionApril
                  2007
              
              Bice
                  #1 (Terryville)
              
              86%
              
              Drilling
 
 On
        our
        Terryville prospect in Lincoln Parish we drilled and completed two wells
        in the
        Cotton Valley interval in the first quarter of 2007. The J.L. Hood #1 and
        the J.
        Huey #1 were both completed as gas wells and are currently producing, on
        a
        combined basis, approximately 2,500 Mcf of gas per day and 150 barrels of
        oil
        per day, net to our interest. We also began drilling operations on the C.M.
        Bice
        #1, an 11,500-foot exploratory well, in April 2007.
  Our
        first
        exploratory well on the Sarepta prospect in Webster Parish, the P. Benoit
        #1,
        targeted a hydrocarbon formation in the Gray sand, but that zone was
        non-productive. We are waiting on availability of a completion rig to attempt
        completion in the Cotton Valley interval. We also drilled the George Staton
        #1,
        a 12,200-foot exploratory well in the Sarepta prospect, and are waiting on
        completion operations to commence.
 
 23
 We
        are
        currently drilling the David Barton #1, a 17,000-foot exploratory well on
        our
        Winnsboro prospect in Richland Parish, targeting the Bossier sands.
 
 ***East
        Texas Bossier***
 We
        have
        acquired a significant acreage position in East Texas targeting the Bossier
        formation which is encountered at depths ranging from 14,000 to 22,000 feet
        in this area. To date, we have acquired approximately 54,000 net acres and
        hold
        up to 50,000 additional acres in the area of our Austin Chalk (Trend) production
        primarily in Burleson, Robertson, Brazos and Milam Counties, Texas.
 
 In
        April,
        we commenced drilling operations on two wells, the Big Bill Simpson #1, a
        19,000-foot exploratory well in Leon County (70% working interest), and the
        Margarita #1, a 20,000-foot exploratory well in Robertson County (100% working
        interest), both targeting the Bossier formation. These wells are very expensive
        to drill and involve a high degree of risk. Depending upon drilling results
        of
        these two wells, we may drill additional Bossier wells in 2007.
 
 ***Utah***
 We
        are
        participating in a joint exploration program with industry partners in the
        Overthrust play in central Utah in which we own a 33% interest. The Vonda
        Christensen 35A31, a 13,500-foot non-operated exploratory well in Sanpete
        County, was drilled and abandoned. We recorded a pre-tax charge of
        $3. 6 million
        in the first quarter of 2007 related to the abandonment of this well. We
        expect
        to participate in the drilling of a second exploratory well to further evaluate
        this acreage in 2008.
 24
 **Supplemental
        Information**
 
 The
        following unaudited information is intended to supplement the consolidated
        financial statements included in this Form 10-Q with data that is not readily
        available from those statements.
 
 **Three
                  Months Ended****March
                  31,****2007**
              
              **2006****Oil
                  and Gas Production Data:**Gas
                  (MMcf)
              
              
              4,327
              
              
              3,463Oil
                  (MBbls)
              
              
              543
              
              
              555Natural
                  gas liquids (MBbls)
              
              
              46
              
              
              48Total
                  (MMcfe)
              
              
              7,861
              
              
              7,081**Average
                  Realized Prices****(a)****:**Gas
                  ($/Mcf)
              
              $
              6.91
              
              $
              7.22Oil
                  ($/Bbl)
              
              $
              55.21
              
              $
              60.01Natural
                  gas liquids ($/Bbl):
              
              $
              33.30
              
              $
              38.90**Gain
                  (Losses) on Settled Derivative Contracts****(a)****:**($
                  in thousands, except per unit)Gas:Net
                  realized gain (loss)
              
              $
              4,509
              
              $
              (2,178
              )Per
                  unit produced ($/Mcf)
              
              $
              1.04
              
              $
              (0.63
              )Oil:Net
                  realized loss
              
              $
              (2,559
              )
              $
              (5,895
              )Per
                  unit produced ($/Bbl)
              
              $
              (4.71
              )
              $
              (10.62
              )**Average
                  Daily Production:**Natural
                  Gas (Mcf):Permian
                  Basin
              
              
              15,389
              
              
              13,824Louisiana
              
              
              22,530
              
              
              9,466Austin
                  Chalk (Trend)
              
              
              2,011
              
              
              3,261Cotton
                  Valley Reef Complex
              
              
              7,697
              
              
              11,439Other
              
              
              451
              
              
              488Total
              
              
              48,078
              
              
              38,478Oil
                  (Bbls):Permian
                  Basin
              
              
              3,096
              
              
              3,216Louisiana
              
              
              1,201
              
              
              1,079Austin
                  Chalk (Trend)
              
              
              1,672
              
              
              1,828Other
              
              
              64
              
              
              44Total
              
              
              6,033
              
              
              6,167Natural
                  Gas Liquids (Bbls):Permian
                  Basin
              
              
              199
              
              
              262Austin
                  Chalk (Trend)
              
              
              265
              
              
              258Other
              
              
              47
              
              
              13Total
              
              
              511
              
              
              533
 
 
 
 
 (Continued)
 25
  **Three
                    Months Ended****March
                    31,****2007**
                
                **2006****Exploration
                    Costs (in thousands):**Abandonment
                    and impairment costs:South
                    Louisiana
                
                $
                7,179
                
                $
                8,008North
                    Louisiana
                
                
                306
                
                
                -Permian
                    Basin
                
                
                43
                
                
                2,202Utah,
                    Montana and Colorado
                
                
                3,577
                
                
                1,933Other
                
                
                -
                
                
                700Total
                
                
                11,105
                
                
                12,843Seismic
                    and other
                
                
                890
                
                
                3,101Total
                    exploration costs
                
                $
                11,995
                
                $
                15,944**Depreciation,
                    Depletion and Amortization (in thousands):**Oil
                    and gas depletion
                
                $
                13,548
                
                $
                13,981Contract
                    drilling depreciation
                
                
                1,383
                
                
                -Other
                    depreciation
                
                
                300
                
                
                729Total
                    DD&A
                
                $
                15,231
                
                $
                14,710**Oil
                    and Gas Costs ($/Mcfe Produced):**Production
                    costs
                
                $
                2.20
                
                $
                2.11Oil
                    and gas depletion
                
                $
                1.72
                
                $
                1.97**Net
                    Wells Drilled****(b)****:**Exploratory
                    Wells
                
                
                5.0
                
                
                7.6Developmental
                    Wells
                
                
                3.5
                
                
                1.7
 (a) No
        derivatives were designated as cash flow hedges in 2007 or 2006. All gains
        or
        losses on settled derivatives were included in loss on derivatives.
 (b) Excludes
        wells being drilled or completed at the end of each period.
 
 **Operating
        Results - Three-Month Periods**
 
 The following discussion compares our results for the three months ended
        March 31, 2007 to the comparative period in 2006. Unless otherwise
        indicated, references to 2007 and 2006 within this section refer to the
        respective quarterly period.
 
 ***Oil
        and gas operating results***
 
 Oil and gas sales in 2007 increased $1 million, or 2%, from 2006, of which
        production variances accounted for a $5.2 million increase and price
        variances accounted for a $4.2 million decrease. Production in 2007 (on an
        Mcfe basis) was 11% higher than 2006. Oil production decreased 2% in 2007
        from
        2006 due primarily to normal production declines, offset in part by higher
        production from new wells in Louisiana. Gas production increased 25% in 2007
        from 2006 due primarily to production attributable to recent drilling activity
        in South Louisiana. In 2007, our realized oil price was 8% lower than 2006,
        while our realized gas price was 4% lower. Historically, the markets for
        oil and
        gas have been volatile, and they are likely to continue to be
        volatile.
 
 Production
        costs, consisting of lease operating expenses, production taxes and other
        miscellaneous marketing costs, increased 15% in 2007 as compared to 2006
        due
        primarily to higher oilfield service costs. After giving effect to an 11%
        increase in oil and gas production on an Mcfe basis, production costs per
        Mcfe
        increased 4% from $2.11 per Mcfe in 2006 to $2.20 per Mcfe in 2007. It is
        likely
        that these factors will continue to contribute to higher production costs
        in
        future periods.
  26
 Oil
        and
        gas depletion expense decreased $433,000, of which rate variances accounted
        for
        a $1.9 million decrease and production variances accounted for a
        $1.5 million increase. On an Mcfe basis, depletion expense decreased 13%
        from $1.97 per Mcfe in 2006 to $1.72 per Mcfe in 2007 due in part to a lower
        depletable cost basis in 2007 compared to the 2006 period in two areas where
        we
        recorded an impairment of proved property under SFAS No. 144 in the last
        half of
        2006. Depletion expense per Mcfe of oil and gas production is an operating
        metric that is indicative of our weighted average cost to find or acquire
        a unit
        of equivalent production. We may realize higher oil and gas depletion rates
        in
        future periods if our exploration activities result in higher finding costs
        in
        2007.
 
 We recorded a provision for impairment of proved properties under SFAS 144
        of
        $565,000 during the first quarter of 2007 due to production performance.
        This
        provision was attributable to two areas in the Permian Basin.
 
 ***Exploration
        costs***
 
 Since we follow the successful efforts method of accounting, our results
        of
        operations are adversely affected during any accounting period in which
        significant seismic costs, exploratory dry hole costs, and unproved acreage
        impairments are expensed.  In 2007, we charged to expense
        $11.1 million of exploration costs, as compared to $12.8 million in
        2006. Most of the 2007 costs were incurred in Louisiana and Utah.
 
 At March 31, 2007, our capitalized unproved oil and gas properties totaled
        $138.9 million, of which approximately $105 million was attributable
        to unproved acreage. Unproved properties are subject to a valuation impairment
        to the extent the carrying cost of a prospect exceeds its estimated fair
        value.
        Therefore, our results of operations in future periods may be adversely affected
        by unproved property impairments.
 
 We plan to spend approximately $186.2 million on exploration and
        development activities in fiscal 2007, of which approximately 78% is expected
        to
        be allocated to exploration activities.  Since exploratory drilling
        involves a high degree of risk, it is likely that a significant portion of
        the
        costs we incur in fiscal 2007 will be charged to exploration costs. However,
        we
        cannot predict our success rates and, accordingly, cannot predict our
        exploration costs related to abandonment and impairment costs.
 
 ***Contract
        Drilling Services***
 In April 2006, we formed a joint venture (“Larclay JV”) with Lariat Services,
        Inc. to construct, own, and operate 12 new drilling rigs. We own a 50% interest
        in Larclay JV. The rigs are being constructed on behalf of Larclay JV by
        Lariat,
        as operations manager. Ten of the rigs were fully constructed at March 31,
        2007.
        Two of the rigs are working for us, seven are working for an affiliate of
        Lariat
        and one is working for other operators. The remaining two rigs are expected
        to
        be fully constructed by June 2007. Although the Company and Lariat own equal
        interests in Larclay JV, the Company meets the definition of the primary
        beneficiary of Larclay JV’s expected cash flows under FIN 46R. As the primary
        beneficiary under FIN 46R, the Company is required to include the accounts
        of
        Larclay JV in the Company’s consolidated financial statements. During the three
        months ended March 31, 2007, we included contract drilling revenues of $8.4
        million, net other operating expenses of $5 million, depreciation expense
        of
        $1.4 million and interest expense of $834,000 in our statement of operations
        (see Note 14 to the consolidated financial statements). Since the Larclay
        JV drilling rigs are partially utilized by us, the reported amounts are net
        of
        any intercompany profits eliminated in consolidation.
  ***General
        and Administrative***
 
 General and administrative (“G&A”) expenses decreased 4% from
        $4.1 million in 2006 to $3.9 million in 2007. Excluding non-cash
        employee compensation, G&A expenses decreased from $3.4 million in 2006
        to $3.3 million in 2007. In 2007, we recorded a $500,000 non-cash
        compensation charge related to our after payout incentive plan and $110,000
        for
        stock-based employee compensation. In 2006, we recorded a $128,000 non-cash
        charge for stock-based employee compensation and a $500,000 non-cash charge
        related to our after payout incentive plan.
 
 ***Interest
        expense***
 Interest
        expense increased 76% from $4.3 million in 2006 to $7.6 million in
        2007 due to a combination of factors. In 2006 and 2007, we used our revolving
        loan facility to partially finance our exploration and
        development
  27
 activities.
        The average daily principal balance outstanding under our revolving credit
        facility for 2007 was $159.1 million compared to $43.5 million for
        2006. Capitalized interest for 2007 was $973,000 compared to $1.2 million
        in 2006. We also included $834,000 of interest expense associated with our
        Larclay JV during 2007.
 
 ***Gain/loss
        on derivatives***
  We
          did
          not designate any derivative contracts in 2007 or 2006 as cash flow hedges;
          therefore all cash settlements and changes resulting from mark-to-market
          valuations have been recorded as gain/loss on derivatives. For the three
          months
          ended March 31, 2007, we reported a $16.8 million net loss on
          derivatives, consisting of an $18.8 million non-cash loss to mark our
          derivative positions to their fair value at March 31, 2007 and a $2 million
          realized gain on settled contracts. For the three months ended March 31,
          2006, we recorded a net loss on derivatives of $1.6 million, consisting of
          a $6.5 million non-cash mark-to-market gain related to changes in
          mark-to-market valuations and an $8.1 million realized loss on settled
          contracts.
 ***Other
          expense***
 
 We
        recorded losses on inventory during 2007 of $9.2 million, including a non-cash
        charge of $8.9 million to write-down inventory to its estimated market value
        at
        March 31, 2007. The write-down resulted primarily from the sale of certain
        surplus equipment at an auction in March 2007. No losses or write-downs were
        recorded during the 2006 period.
 
 ***Income
        tax expense (benefit)***
 
 Our effective income tax rate in 2007 of 34.7% differed from the statutory
        federal rate of 35% due primarily to increases in the tax provision related
        primarily to the effects of the recently-enacted Texas Margin Tax and certain
        non-deductible expenses, offset in part by tax benefits derived from statutory
        depletion deductions.
  **Liquidity
        and Capital Resources**
 
 ***Overview***
 
 Our
        primary financial resource is our base of oil and gas reserves. We pledge
        our
        producing oil and gas properties to a group of banks to secure our revolving
        credit facility. The banks establish a borrowing base by making an estimate
        of
        the collateral value of our oil and gas properties. We borrow funds on the
        revolving credit facility as needed to supplement our operating cash flow
        as a
        financing source for our capital expenditure program. Our ability to fund
        our
        capital expenditure program is dependent upon the level of product prices
        and
        the success of our exploration program in replacing our existing oil and
        gas
        reserves. If product prices decrease, our operating cash flow may decrease
        and
        the banks may require additional collateral or reduce our borrowing base,
        thus
        reducing funds available to fund our capital expenditure program. The effects
        of
        product prices on cash flow can be mitigated through the use of commodity
        derivatives. If we are unable to replace our oil and gas reserves through
        our
        exploration program, we may also suffer a reduction in our operating cash
        flow
        and access to funds under the revolving credit facility. Under extreme
        circumstances, product price reductions or exploration drilling failures
        could
        allow the banks to seek to foreclose on our oil and gas properties, thereby
        threatening our financial viability.
 
 In
        2005,
        we issued $225 million of aggregate principal amount of Senior Notes and
        used the net proceeds to repay all amounts outstanding on the revolving credit
        facility at that time. However, we relied heavily on advances under the
        revolving credit facility to finance a significant portion of our exploration
        and development activities in 2006 and the first quarter of 2007. At March
        31,
        2007, we had $165 million outstanding on the revolving credit
        facility.
 
 Our
        expenditures for exploration and development activities for the first quarter
        of
        2007 exceeded our cash flow from operating activities for the same period
        by
        approximately $24.3 million, and we expect our spending during the
        remainder of 2007 to outpace our operating cash flow, although not by as
        large a
        margin. We cannot predict our drilling success on exploratory prospects,
        and our
        future results of operations and financial condition could be adversely affected
        by unsuccessful exploratory drilling results. In this section, we will describe
        our current plans for
  28
 capital
          spending, identify the capital resources available to finance our capital
          spending, and discuss the principal factors that can affect our liquidity
          and
          capital resources.
  ***Capital
        expenditures***
 
 We
        incurred expenditures for exploration and development activities of
        $60.6 million during the first three months of 2007 and have increased our
        estimates for planned expenditures for fiscal 2007 from $170.1 million to
        $186.2 million. The following table summarizes, by area, our actual
        expenditures for exploration and development activities for the first quarter
        of
        2007 and our planned expenditures for the year ending December 31,
        2007.
 
 **Actual**
              
              **Planned****Expenditures**
              
              **Expenditures**
              
              **Year
                  2007****Three
                  Months Ended**
              
              **Year
                  Ending**
              
              **Percentage****March
                  31, 2007**
              
              **December
                  31, 2007**
              
              **of
                  Total****(In
                  thousands)**South
                  Louisiana
              
              $
              32,200
              
              $
              58,600
              
              
              32
              %North
                  Louisiana
              
              
              14,300
              
              
              58,300
              
              
              31
              %East
                  Texas Bossier
              
              
              2,500
              
              
              34,100
              
              
              18
              %Permian
                  Basin
              
              
              8,300
              
              
              24,500
              
              
              13
              %Austin
                  Chalk (Trend)
              
              
              300
              
              
              6,000
              
              
              3
              %Utah
              
              
              2,900
              
              
              3,000
              
              
              2
              %Other
              
              
              100
              
              
              1,700
              
              
              1
              %$
              60,600
              
              $
              186,200
              
              
              100
              %
  Our
        actual expenditures during fiscal 2007 may be substantially higher or lower
        than
        these estimates since our plans for exploration and development activities
        may
        change during the year. Other factors, such as prevailing product prices
        and the
        availability of capital resources, could also increase or decrease the ultimate
        level of expenditures during fiscal 2007.
 
 Approximately
        78% of the planned expenditures relate to exploratory prospects. Exploratory
        prospects involve a higher degree of risk than developmental prospects. To
        offset the higher risk, we generally strive to achieve a higher reserve
        potential and rate of return on investments in exploratory prospects. We
        do not
        attempt to forecast our success rate on exploratory drilling. Accordingly,
        these
        current estimates do not include costs we may incur to complete any future
        successful exploratory wells and construct the required production facilities
        for these wells. Also, we are actively searching for other opportunities
        to
        increase our oil and gas reserves, including the evaluation of new prospects
        for
        exploratory and developmental drilling activities and potential acquisitions
        of
        proved oil and gas properties. We cannot predict our drilling success on
        exploratory prospects, and our future results of operations and financial
        condition could be adversely affected by unsuccessful exploratory drilling
        results.
 
 Our
        expenditures for exploration and development activities for the three months
        ended March 31, 2007 exceeded our cash flow from operating activities for
        the
        same period by approximately $24.3 million, and we expect our spending
        during the remainder of 2007 to outpace our operating cash flow, although
        not by
        as large a margin. To the extent possible, we intend to finance this shortfall
        by borrowings on the revolving credit facility. Our internal cash flow forecasts
        indicate that the amount of funds available to us under our revolving credit
        facility, when combined with our anticipated operating cash flow, will be
        sufficient to finance our capital expenditures and will provide us with adequate
        liquidity at least through 2007. Although we believe the assumptions and
        estimates made in our forecasts are reasonable, uncertainties exist which
        could
        cause the borrowing base to be less than expected, cash flow to be less than
        expected, or capital expenditures to be more than expected. In the event
        we lack
        adequate liquidity to finance our expenditures in 2007, we are currently
        considering several options for alternative capital resources, including
        the
        sale of assets and the request for an increase in the amount of funds available
        under our revolving credit facility based on recent additions to proved
        reserves.
 
 We
        have
        placed orders for two 2,000 horsepower rigs for possible use in our Bossier
        drilling program in North Louisiana and East Texas. At March 31, 2007, we
        had invested $11.5 million in these rigs and were committed under firm
        purchase contracts for an additional $13 million. We estimate that the
        combined construction cost of both rigs will
  29
 be
          approximately $27 million. We are currently evaluating our need for these
          drilling rigs, and depending on that evaluation, we may elect to sell the
          rigs,
          or we may seek financing for the remaining cost of these
          rigs.
  ***Cash
          flow provided by operating activities***
 
 Substantially
        all of our cash flow from operating activities is derived from the production
        of
        our oil and gas reserves. We use this cash flow to fund our on-going exploration
        and development activities in search of new oil and gas reserves. Variations
        in
        cash flow from operating activities may impact our level of exploration and
        development expenditures.
 
 Cash
        flow
        provided by operating activities for the three months ended March 31, 2007
        decreased $1.3 million, or 4%, as compared to the corresponding period in
        2006 due to the combined effects of several factors. Oil and gas sales, net
        of
        production costs, general and administrative costs and interest expense,
        were
        $4.4 million lower in the 2007 period as compared to the same period in
        2006. Our primary source of cash from operating activities is our oil and
        gas
        sales, net of production costs. Our cash flow provided by operating activities
        is subject to material variation from changes in oil and gas production levels
        and product prices. Settlements on derivative contracts, excluding those
        contracts that contain a financing element as in the case of the contracts
        assumed in our acquisition of Southwest Royalties, Inc. in May 2004, were
        $2.3 million lower in the 2007 period compared to the 2006 period. Interest
        expense increased $3.3 million in the 2007 period due primarily to higher
        levels of indebtedness resulting from our aggressive exploration and development
        activities.
 
 ***Credit
        facility***
 
 A
        group
        of banks have provided us with a revolving credit facility on which we have
        historically relied for both our short-term liquidity (working capital) and
        our
        long-term financing needs. The funds available to us at any time under this
        revolving credit facility are limited to the amount of the borrowing base
        established by the banks. As long as we have sufficient availability under
        this
        credit facility to meet our obligations as they come due, we will have
        sufficient liquidity and will be able to fund any short-term working capital
        deficit.
 
 At
        the
        beginning of 2007, we had an outstanding balance under the revolving credit
        facility of $140 million, and the borrowing base was $200 million,
        providing us with available funds of $40.2 million after accounting for
        outstanding letters of credit. During 2007, we generated cash flow from
        operating activities of $36.2 million and received cash proceeds of
        $6.6 million from sales of assets and issuances of common stock. We also
        used cash to pay for additions to property and equipment of $55.7 million
        (excluding Larclay JV) and paid $5.6 million to settle derivatives with
        financing elements. To finance the excess of expenditures over cash flow,
        we
        borrowed $25 million on the revolving credit facility. In addition, Larclay
        JV paid $19.3 million for property and equipment and borrowed
        $8.7 million, resulting in a $10.6 million reduction in
        liquidity.
 
 Using
        the
        revolving credit facility for both our short-term liquidity and long-term
        financing needs can cause unusual fluctuations in our reported working capital,
        depending on the timing of cash receipts and expenditures. On a daily basis,
        we
        use most of our available cash to pay down our outstanding balance on the
        revolving credit facility, which is classified as a non-current liability
        since
        we currently have no required principal reductions. As we use cash to pay
        a
        non-current liability, our reported working capital decreases. Conversely,
        as we
        draw on the revolving credit facility for funds to pay current liabilities
        (such
        as payables for drilling and operating costs), our reported working capital
        increases. Also, volatility in oil and gas prices can cause significant
        fluctuations in reported working capital as we record changes in the fair
        value
        of derivatives from period to period. For these reasons, the working capital
        covenant related to the revolving credit facility requires us to
        (i) include the amount of funds available under this facility as a current
        asset, (ii) exclude current assets and liabilities related to the fair
        value of derivatives, and (iii) exclude current maturities of vendor
        finance obligations, if any, when computing the working capital ratio at
        any
        balance sheet date.
 
 Working
        capital computed for loan compliance purposes differs from our working capital
        in accordance with generally accepted accounting principles (GAAP). Since
        compliance with financial covenants is a material requirement under the credit
        facilities, we consider the loan compliance working capital to be useful
        as a
        measure of our liquidity because it includes the funds available to us under
        the
        revolving credit facility and is not affected by the volatility in working
        capital caused by changes in fair value of derivatives. Our reported working
        capital deficit
  30
 increased
          from $23.1 million at December 31, 2006 to $55.6 million at
          March  31, 2007 due primarily to a combination of factors, including
          decreases in inventory and an increase in the net liability for the fair
          value
          for derivatives. After giving effect to the adjustments, our working capital
          computed for loan compliance purposes was a positive $18.4 million at
          March 31, 2007, as compared to a positive $36.9 million at
          December 31, 2006. The following table reconciles our GAAP working capital
          to the working capital computed for loan compliance purposes at March 31,
          2007
          and December 31, 2006.
  **March
                  31,**
              
              **December
                  31,****2007**
              
              **2006****(In
                  thousands)**Working
                  capital (deficit) per GAAP
              
              $
              (55,613
              )
              $
              (23,068
              )Add
                  funds available under the revolving credit facility
              
              
              29,196
              
              
              40,196Exclude
                  fair value of derivatives classified as current assets or current
                  liabilities
              
              
              25,718
              
              
              5,993Exclude
                  current assets and current liabilities of Larclay JV
              
              
              19,095
              
              
              13,759Working
                  capital per loan covenant
              
              $
              18,396
              
              $
              36,880
  Since
        we
        use this revolving credit facility for both short-term liquidity and long-term
        financing needs, it is important that we comply in all material respects
        with
        the loan agreement, including financial covenants that are computed quarterly.
        The working capital covenant requires us to maintain positive working capital
        using the computations described above. Another financial covenant under
        the
        credit facility requires us to maintain a ratio of indebtedness to cash flow
        of
        no more than 3 to 1. While we were in compliance with all financial and
        non-financial covenants at March 31, 2007, our increased leverage and
        reduced liquidity may result in our failing to comply with one or more of
        these
        covenants in the future.  If we fail to meet any of these loan covenants,
        we would ask the banks to allow us sufficient time to obtain additional capital
        resources through alternative means. If a suitable arrangement could not
        be
        reached with the banks, the banks could accelerate the indebtedness and seek
        to
        foreclose on the pledged assets.
 
 The
        banks
        redetermine the borrowing base under the revolving credit facility at least
        twice a year, in May and November. The November 2006 borrowing base review
        resulted in maintaining the borrowing base at $200 million. We presently
        anticipate that the banks will authorize an increase in the borrowing base
        in
        connection with the May 2007 borrowing base review, but the amount, if any,
        of
        such increase is not known at this time. If at any time, the borrowing base
        is
        less than the amount of outstanding indebtedness, we will be required to
        (i) pledge additional collateral, (ii) prepay the excess in not more
        than five equal monthly installments, or (iii) elect to convert the entire
        amount of outstanding indebtedness to a term obligation based on amortization
        formulas set forth in the loan agreement. We have relied heavily on advances
        under the revolving credit facility to finance a significant portion of our
        exploration and development activities in fiscal 2006 and the first quarter
        of
        2007. At March 31, 2007, we had $165 million outstanding on the revolving
        credit facility.
 
 ***73⁄4%
        Senior Notes due 2013***
 
 In
        July
        2005, we issued, in a private placement, $225 million of aggregate
        principal amount of Senior Notes. The Senior Notes were issued at face value
        and
        will bear interest at 73⁄4% per year, payable semi-annually on February 1 and
        August 1 of each year, beginning February 1, 2006. After the payment of typical
        transaction expenses, net proceeds of approximately $217 million were used
        to repay amounts outstanding on our secured credit facilities and for general
        corporate purposes, including the funding of planned exploration and development
        activities.
 
 At
        any
        time prior to August 1, 2008, we may redeem up to 35% of the aggregate principal
        amount of the Senior Notes with the proceeds of certain equity offerings
        at a
        redemption price of 107.75% of the principal amount, plus accrued and unpaid
        interest. In addition, prior to August 1, 2009, we may redeem some or all
        of the
        Senior Notes at a redemption price equal to 100% of the principal amount
        of the
        Senior Notes to be redeemed, plus a make-whole premium, plus any accrued
        and
        unpaid interest. On and after August 1, 2009, we may redeem some or all of
        the
        Senior Notes at redemption prices (expressed as percentages of principal
        amount)
        equal to 103.875% for the twelve-month period beginning on August 1, 2009,
        101.938% for the twelve-month period beginning on August 1, 2010, and 100.00%
        beginning on August 1, 2011, for any period thereafter, in each case plus
        accrued and unpaid interest.
 
 31
 The
        Indenture governing the Senior Notes restricts our ability and the ability
        of
        our restricted subsidiaries to: (i) borrow money; (ii) issue
        redeemable and preferred stock; (iii) pay distributions or dividends;
        (iv) make investments; (v) create liens without securing the Notes;
        (vi) enter into agreements that restrict dividends from subsidiaries;
        (vii) sell certain assets or merge with or into other companies;
        (viii) enter into transactions with affiliates; (ix) guarantee
        indebtedness; and (x) enter into new lines of business. These covenants are
        subject to a number of important exceptions and qualifications. We were in
        compliance with these covenants at March 31, 2007.
 
 ***Alternative
        capital resources***
 
 Although
        our base of oil and gas reserves, as collateral for both of our credit
        facilities, has historically been our primary capital resource, we have in
        the
        past, and we believe we could in the future, use alternative capital resources,
        such as asset sales, vendor financing arrangements, and/or public or private
        issuances of common stock. We could also issue senior or subordinated debt
        or
        preferred stock in a public or a private placement if we choose to raise
        capital
        through either of these markets. While we believe we would be able to obtain
        funds through one or more of these alternatives, if needed, there can be
        no
        assurance that these capital resources would be available on terms acceptable
        to
        us.
  **Item
        3** **-** ****  **Quantitative
        and Qualitative Disclosure About Market Risks**
 
 Our
        business is impacted by fluctuations in commodity prices and interest rates.
        The
        following discussion is intended to identify the nature of these market risks,
        describe our strategy for managing such risks, and to quantify the potential
        affect of market volatility on our financial condition and results of
        operations.
 
 **Oil
        and Gas Prices**
 
 Our
        financial condition, results of operations, and capital resources are highly
        dependent upon the prevailing market prices of, and demand for, oil and natural
        gas. These commodity prices are subject to wide fluctuations and market
        uncertainties due to a variety of factors that are beyond our control. These
        factors include the level of global demand for petroleum products, foreign
        supply of oil and gas, the establishment of and compliance with production
        quotas by oil-exporting countries, weather conditions, the price and
        availability of alternative fuels, and overall economic conditions, both
        foreign
        and domestic. We cannot predict future oil and gas prices with any degree
        of
        certainty. Sustained weakness in oil and gas prices may adversely affect
        our
        financial condition and results of operations, and may also reduce the amount
        of
        net oil and gas reserves that we can produce economically. Any reduction
        in
        reserves, including reductions due to price fluctuations, can reduce the
        borrowing base under our revolving credit facility and adversely affect our
        liquidity and our ability to obtain capital for our exploration and development
        activities. Similarly, any improvements in oil and gas prices can have a
        favorable impact on our financial condition, results of operations and capital
        resources. Based on December 31, 2006 reserve estimates, we project that a
        $1.00 drop in the price per Bbl of oil and a $.50 drop in the price per Mcf
        of
        gas would reduce our gross revenues for the year ending December 31, 2007
        by $10.7 million.
 
 From
        time
        to time, we utilize commodity derivatives, consisting primarily of swaps,
        floors
        and collars to attempt to optimize the price received for our oil and natural
        gas production. When using swaps to hedge our oil and natural gas production,
        we
        receive a fixed price for the respective commodity and pay a floating market
        price as defined in each contract (generally NYMEX futures prices), resulting
        in
        a net amount due to or from the counterparty. In floor transactions, we receive
        a fixed price (put strike price) if the market price falls below the put
        strike
        price for the respective commodity. If the market price is greater than the
        put
        strike price, no payments are due from either party. Costless collars are
        a
        combination of puts and calls, and contain a fixed floor price (put strike
        price) and ceiling price (call strike price). If the market price for the
        respective commodity exceeds the call strike price or falls below the put
        strike
        price, then we receive the fixed price and pay the market price. If the market
        price is between the call and the put strike prices, no payments are due
        from
        either party. Commodity derivatives are settled monthly as the contract periods
        mature. The commodity derivatives we use differ from futures contracts in
        that
        there is not a contractual obligation that requires or permits the future
        physical delivery of the hedged products. We do not enter into commodity
        derivatives for trading purposes. In addition to commodity derivatives, we
        may,
        from time to time, sell a portion of our gas production under short-term
        contracts at fixed prices.
 
 32
 The
        decision to initiate or terminate commodity hedges is made by management
        based
        on its expectation of future market price movements. We have no set goals
        for
        the percentage of our production we hedge and we do not use any formulas
        or
        triggers in deciding when to initiate or terminate a hedge. If we enter into
        swaps or collars and the floating market price at the settlement date is
        higher
        than the fixed price or the fixed ceiling price, we will forego revenue we
        would
        have otherwise received. If we terminate a swap, collar or floor because
        we
        anticipate future increases in market prices, we may be exposed to downside
        risk
        that would not have existed otherwise.
 
 The
        following summarizes information concerning our net positions in open commodity
        derivatives applicable to periods subsequent to March 31, 2007. The
        settlement prices of commodity derivatives are based on NYMEX futures
        prices.
 
 **Collars:**
 **Gas**
              
              **Oil****MMBtu****(a)**
              
              **Floor**
              
              **Ceiling**
              
              **Bbls**
              
              **Floor**
              
              **Ceiling**Production
                  Period:2ndQuarter 2007
              
              
              459,000
              
              $
              4.00
              
              $
              5.18
              
              
              141,000
              
              $
              23.00
              
              $
              25.203rdQuarter 2007
              
              
              459,000
              
              $
              4.00
              
              $
              5.18
              
              
              141,000
              
              $
              23.00
              
              $
              25.204thQuarter 2007
              
              
              459,000
              
              $
              4.00
              
              $
              5.18
              
              
              141,000
              
              $
              23.00
              
              $
              25.202008
              
              
              1,279,000
              
              $
              4.00
              
              $
              5.15
              
              
              392,000
              
              $
              23.00
              
              $
              25.072,656,000
              
              
              
              
              
              
              
              
              815,000
 
 **Swaps:**
 **Gas**
                
                **Oil****MMBtu****(a)**
                
                **Price**
                
                **Bbls**
                
                **Price**Production
                    Period:2ndQuarter 2007
                
                
                2,600,000
                
                $
                8.16
                
                
                -
                
                $
                -3rdQuarter 2007
                
                
                2,400,000
                
                $
                8.34
                
                
                75,000
                
                $
                72.754thQuarter 2007
                
                
                2,400,000
                
                $
                8.34
                
                
                225,000
                
                $
                72.752008
                
                
                6,300,000
                
                $
                8.19
                
                
                720,000
                
                $
                65.6013,700,000
                
                
                
                
                
                1,020,000
 (a) One
        MMBtu equals one Mcf at a Btu factor of 1,000.
  In
        January 2007, we terminated certain fixed-price oil swaps covering 375,000
        barrels at a price of $55.35 per barrel from April 2007 through August 2007,
        resulting in an aggregate realized gain of approximately $6.5 million,
        which will be collected from the counterparty monthly during 2007.
 
 In
        July
        2006, we also terminated certain fixed-price oil swaps covering 225,000 barrels
        at a price of $80.45 per barrel from April 2007 through December 2007, resulting
        in an aggregate loss of approximately $1.8 million, which will be paid to
        the counterparty monthly during 2007.
 
 We use a sensitivity analysis technique to evaluate the hypothetical effect
        that
        changes in the market value of oil and gas may have on the fair value of
        our
        commodity derivatives. A $1 per barrel change in the price of oil and a
        $.50 per MMBtu change in the price of gas would change the fair value of
        our
        commodity derivatives by approximately $9 million.
 
 **Interest
        Rates**
 
 We are exposed to interest rate risk on our long-term debt with a variable
        interest rate. At March 31, 2007, our variable rate debt had a carrying
        value of $240 million, which approximated its fair value. At March 31,
        2007, our fixed rate debt had a carrying value of $225 million and an
        approximate fair value of $209.8 million, based on current market quotes.
        We estimate that the hypothetical change in the fair value of our fixed-rate,
        long-term debt resulting from a 100-basis point change in interest rates
        would
        be approximately $9.9 million.
 
 33
 We
        are a
        party to interest rate swaps that were acquired in connection with the
        acquisition of Southwest Royalties, Inc. in May 2004. Under these derivatives,
        we pay a fixed rate for the notional principal balances and receives a floating
        market rate based on LIBOR. The following summarizes information concerning
        our
        net positions in open interest rate swaps applicable to periods subsequent
        to
        March 31, 2007.
 
 **Principal**
              
              **Fixed
                  Libor****Balance**
              
              **Rates**Period:April
                  1, 2007 to November 1, 2007
              
              $
              50,000,000
              
              
              5.19
              %November
                  1, 2007 to November 1, 2008
              
              $
              45,000,000
              
              
              5.73
              %
  The interest rate swaps in the preceding table expose us to market risks
        for
        decreases in interest rates during the periods shown.
 
 
 **Item
        4 -** ****  **Controls
        and Procedures**
 
 **Disclosure
        Controls and Procedures**
 
 In
        September 2002, our Board of Directors adopted a policy designed to establish
        disclosure controls and procedures that are adequate to provide reasonable
        assurance that our management will be able to collect, process and disclose
        both
        financial and non-financial information, on a timely basis, in our reports
        to
        the Securities and Exchange Commission (“SEC”) and other communications with our
        stockholders. Disclosure controls and procedures include all processes necessary
        to ensure that material information is recorded, processed, summarized and
        reported within the time periods specified in the SEC’s rules and forms, and is
        accumulated and communicated to our management, including our chief executive
        and chief financial officers, to allow timely decisions regarding required
        disclosures.
 
 With
        respect to our disclosure controls and procedures:
 
 ·
            Management
                has evaluated the effectiveness of our disclosure controls and procedures
                as of the end of the period covered by this
                report; 
 ·
            This
                evaluation was conducted under the supervision and with the participation
                of our management, including our chief executive and chief financial
                officers; and 
 ·
            It
                is the conclusion of our chief executive and chief financial officers
                that
                these disclosure controls and procedures are effective in ensuring
                that
                information that is required to be disclosed by the Company in reports
                filed or submitted with the SEC is recorded, processed, summarized
                and
                reported within the time periods specified in the rules and forms
                established by the SEC. 
 **Changes
        in Internal Control Over Financial Reporting**
 
 No
        changes in internal control over financial reporting were made during the
        quarter ended March 31, 2007 that have materially affected, or are
        reasonably likely to materially affect, our internal control over financial
        reporting.
 34
  **PART
        II. FINANCIAL INFORMATION**
 
 
 **Item
        1 -** **** **Legal
        Proceedings**
 
 We
        are a
        co-plaintiff in a lawsuit involving a dispute over rights to produce
        hydrocarbons under certain leases in Alabama. We and the other parties to
        the
        lawsuit have tentatively agreed to settle the lawsuit. Once the agreement
        is
        executed and binding, we will record a gain on settlement of approximately
        $2.9 million. Final settlement is expected to occur in the second quarter
        of 2007.
 
 
 **Item
        1A-** **Risk
        Factors**
 
 In
        evaluating all forward-looking statements, you should specifically consider
        various factors that may cause actual results to vary from those contained
        in
        the forward-looking statements. Our risk factors are included in our Annual
        Report on Form 10-K for the year ended December 31, 2006, as filed
        with the U.S. Securities and Exchange Commission on March 16, 2007 and
        available at www.sec.gov .
        There
        have been no material changes to these risk factors since the filing of our
        Form 10-K.
 
 **Item
        6 -**  **Exhibits**
 
 **Exhibits**
 
 **3.1
              
              Second
                  Restated Certificate of Incorporation of the Company, filed as
                  Exhibit 3.1
                  to our Form S-2 Registration Statement, Commission File No.
                  333-13441**3.2
              
              Certificate
                  of Amendment of Second Restated Certificate of Incorporation of
                  Clayton
                  Williams Energy, Inc., filed as Exhibit 3.1 to our Form 10-Q for
                  the
                  period ended September 30, 2000††**3.3
              
              Corporate
                  Bylaws of Clayton Williams Energy, Inc., as amended, filed as
                  Exhibit 3.1 to our Current Report on Form 8-K filed with the
                  Commission on March 8, 2007††**4.1
              
              Indenture,
                  dated July 20, 2005, among Clayton Williams Energy, Inc., the Subsidiary
                  Guarantors and Wells Fargo Bank, National Association, as Trustee,
                  filed
                  as Exhibit 4.1 to our Current Report on Form 8-K filed with the
                  Commission on July 22, 2005††**4.2
              
              Registration
                  Rights Agreement dated July 20, 2005, among Clayton Williams Energy,
                  Inc.,
                  the Subsidiary Guarantors and J.P. Morgan Securities Inc., filed
                  as
                  Exhibit 4.2 to our Current Report on Form 8-K filed with the
                  Commission on July 22, 2005††**10.1†
              
              Southwest
                  Royalties Reward Plan dated January 15, 2007, filed as Exhibit 10.1
                  to the Company’s Current Report on Form 8-K filed with Commission on
                  January 18, 2007††*31.1
              
              Certification
                  by the President and Chief Executive Officer of the Company pursuant
                  to
                  Rule 13(a) - 14(a) of the Securities Exchange Act of
                  1934
  35
  **Exhibits
        (Continued)**
 
 *31.2
              
              Certification
                  by the Chief Financial Officer of the Company pursuant to Rule
                  13(a) - 14(a) of the Securities Exchange Act of
                  1934*32
              
              Certifications
                  by the Chief Executive Officer and Chief Financial Officer of the
                  Company
                  pursuant to
                  18 U.S.C. § 1350
 
 *  Filed
        herewith
 **  Incorporated
        by reference to the filing indicated
 †  Identifies
        an Exhibit that consists of or includes a management contract or compensatory
        plan or arrangement
 ††  Filed
        under our Commission File No. 001-10924
   
 
 36
 
 **CLAYTON
        WILLIAMS ENERGY, INC.**
 **SIGNATURES**
 
 
 
 Pursuant
        to the requirements of the Securities Exchange Act of 1934, the Registrant
        has
        duly caused this report to be signed on its behalf by the undersigned thereto
        duly authorized.
 
 
 
 **CLAYTON
                  WILLIAMS ENERGY, INC.**
 
 
 
 Date:
              May
                  8, 2007
              By:
              */s/
                  L. Paul Latham*L.
                  Paul LathamExecutive
                  Vice President and ChiefOperating
                  Officer
 
 
 
 Date:
              May
                  8, 2007
              By:
              */s/
                  Mel G. Riggs*Mel
                  G. RiggsSenior
                  Vice President and Chief FinancialOfficer


37